Total-Deepwater Reference Book[1]

DEEP W ATER REFERE N CE BO O K

Installation Vessels Sealines Subsea Control Systems ROVS and Tools Risers Umbilicals

Tie-in Systems

Subsea Production Systems

SEPTEMBER 2000

TotalFinaElf

DEEPWATER REFERENCE BOOK

DEEPWATER REFERENCE BOOK PREFACE

The Deepwater Reference Book has been prepared by the Advanced Technology Department in order to assist engineers involved with development studies and projects in deepwater. The book is organised in three (3) volumes as follows : !"Volume 1 : Subsea Production Systems, Sealines, Risers !"Volume 2 : Umbilicals, Subsea Control Systems !"Volume 3 : Deepwater Installation Vessels, Tie-in Systems, ROVs and Tooling This book has been designed for use as a quick first point of reference for engineers who are not necessarily specialists in the areas of technology discussed. It is not an operations or design manual and therefore does not include Company Specifications or (e.g.) recommended procedures for installing equipment subsea. However, it will enable an engineer to grasp the key points and industry jargon associated with a particular subject, in order to approach the relevant specialists and contractors involved. The Deepwater Reference Book presents the state of the art with respect to technology associated with deepwater field development from seabed to surface. The book does not cover technology associated with drilling operations (i.e. subsurface) or floating production systems, which are not specific to deepwater. This reference book is a living document that was up to date at the time of writing in 1999 – 2000. With the passage of time the information contained within this document will be superseded as new technology is brought onto the market. For this reason the book is designed to incorporate revisions within each chapter, which should be performed at the appropriate time by the Advanced Technology Department (or similar function) within the Development Studies Group. It is envisaged that once every five (5) years may be a realistic timeframe to consider such a revision. Whilst much of the information contained within this document is available within the public domain, the Deepwater Reference Book is proprietary to TOTALFINAELF and should not be passed outside of the Group or its affiliates.

J G CUTLER JC BERGER

Rev. 0 30/09/2000 DGEP/SCR/ED/TA

PREFACE

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DOCUMENT REVISIONS

VOLUME NUMBER

DESCRIPTION OF REVISION

DATE OF REVISION

VOLUME ONE

Original Document

30/09/2000

Original Document

30/09/2000

Original Document

30/09/2000

Rev. 0

VOLUME TWO Rev. 0

VOLUME THREE Rev. 0

Acknowledgements

The following significant contributions are acknowledged in the preparation of this document : SEAL Engineering S.A.

Nimes, FRANCE

Subsea Control Services Ltd

London, UK

Mustang Engineering, Inc.

Houston, USA


PREFACE

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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK SUBSEA PRODUCTION SYSTEMS


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TABLE OF CONTENTS

1

INTRODUCTION ............................................................................................................ 5 1.1

SCOPE.................................................................................................................................5

1.2

REGULATIONS, CODES AND STANDARDS ..............................................................................6

1.2.1

International Specifications...........................................................................................6

1.2.2

UK Statutory Instruments..............................................................................................7

1.2.3

NORSOK Standards .....................................................................................................7

1.3

2

DEFINITIONS AND ABBREVIATIONS ........................................................................................8

SUBSEA PRODUCTION EQUIPMENT........................................................................ 12 2.1

INTRODUCTION ..................................................................................................................12

2.2

SUBSEA W ELLHEADS .........................................................................................................13

2.2.1

Functions of Subsea Wellheads .................................................................................13

2.2.2

Types of Subsea Production Wellheads.....................................................................14

2.2.3

Wellhead Connector Profiles ......................................................................................15

2.2.4

Tubing Spool Adapters ...............................................................................................16

2.2.5

Casing and Tubing Hanger Interface..........................................................................16

2.2.6

Wellhead Guide Structures.........................................................................................18

2.2.7

Loads on Wellheads ...................................................................................................20

2.2.8

Subsea Wellhead Materials ........................................................................................20

2.2.9

Description of Typical Subsea Wellhead System.......................................................20

2.2.10 Wellhead Running Tools.............................................................................................26 2.2.11 Typical Subsea Wellhead Installation Procedures .....................................................31 2.3

SUBSEA CHRISTMAS TREES ...............................................................................................32

2.3.1

Functions of Subsea Trees.........................................................................................32

2.3.2

Types of Subsea Trees...............................................................................................33

2.3.3

Components of a Typical Subsea Tree ......................................................................42

2.3.4

Pressure and Structural Design Considerations of Subsea Trees.............................44

2.3.5

Subsea Tree Installation and Well Intervention Considerations ................................48

2.3.6

Subsea Tree Materials, Corrosion and Erosion Design .............................................51

2.3.7

Tree Mounted Controls and Instrumentation..............................................................54

2.3.8

Flow Assurance Considerations .................................................................................54

2.3.9

Deep Water Design Considerations ...........................................................................55

2.3.10 Factory Acceptance, Performance Verification, and System Integration Testing.....57 2.3.11 Manufacturers Capabilities .........................................................................................62


SUBSEA PRODUCTION SYSTEMS

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3

SUBSEA PRODUCTION MANIFOLDS AND TEMPLATES......................................... 63 3.1

4


OVERVIEW OF FUNCTIONS OF SUBSEA PRODUCTION MANIFOLDS & TEMPLATES .................63

3.1.1

Subsea Production Manifolds.....................................................................................64

3.1.2

Subsea Templates ......................................................................................................65

3.2

FEATURES OF TYPICAL SUBSEA PRODUCTION MANIFOLD OR TEMPLATE .............................66

3.3

DESIGN CONSIDERATIONS .................................................................................................68

3.3.1

Number of Wells .........................................................................................................68

3.3.2

Production Piping........................................................................................................68

3.3.3

Bottom Conditions.......................................................................................................69

3.3.4

Installation Method......................................................................................................70

3.3.5

Tie-In Requirements ...................................................................................................71

3.3.6

Flow Assurance ..........................................................................................................72

3.3.7

Deep Water.................................................................................................................73

3.4

ANCILLARY EQUIPMENT ......................................................................................................73

3.4

ANCILLARY EQUIPMENT .....................................................................................................74

3.4.1

Valves .........................................................................................................................74

3.4.2

Chokes ........................................................................................................................75

3.4.3

Flowline Connectors ...................................................................................................77

3.4.4

Flow Meters ................................................................................................................78

3.4.5

Sand Monitoring..........................................................................................................78

SUBSEA SYSTEM INTERFACE REQUIREMENTS .................................................... 79 4.1

PRODUCTION CONTROL SYSTEM........................................................................................79

4.1.1

Types of Control Systems...........................................................................................80

4.1.2

Production Control System Components and Functions ...........................................82

4.1.3

INSTALLATION AND WORKOVER CONTROL SYSTEM (IWOCS) ........................88

4.1.4

Umbilicals And Flying Leads.......................................................................................93

4.1.5

ROV Interface ...........................................................................................................105

4.2

FLOWLINE TIE-INS ...........................................................................................................108

4.2.1

Flowline Tie-In Design Issues...................................................................................109

4.2.2

Flowline Tie-In Methods............................................................................................110

4.3

INSTALLATION AND W ORKOVER RISER SYSTEMS ..............................................................113

4.3.1

INTRODUCTION ......................................................................................................113

4.3.2

Riser System Design ................................................................................................113

4.3.3

Interface Considerations...........................................................................................117

4.3.4

Types of Installation and Workover Riser Systems..................................................117

4.3.5

Well Test and Clean-Up of Wells..............................................................................147

4.4

SYSTEM COMMISSIONING AND START-UP .........................................................................147



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5

FIELD ARCHITECTURE .............................................................................................148 5.1

FIELD ARCHITECTURE CONSIDERATIONS ..........................................................................148

5.2

WELL GROUPING .............................................................................................................150

5.2.1

Satellite Wells ...........................................................................................................151

5.2.2

Template and Clustered Well Developments ...........................................................151

5.3

DRILLING AND W ELL INTERVENTION CONSIDERATIONS .....................................................153

5.4

INTRAFIELD FLOWLINES ...................................................................................................153

5.4.1

Flowline Routing .......................................................................................................153

5.4.2

Tie-Back Distance.....................................................................................................154

5.4.3

Commingling of Production.......................................................................................154

5.4.4

Well Testing .............................................................................................................. 155

5.4.5

Pigging ......................................................................................................................155

5.5

6


FUTURE DEVELOPMENT, EXPANSION ...............................................................................157

RISK ASSESSMENT AND MANAGEMENT ...............................................................158 6.1

POTENTIAL AREAS OF RISK ..............................................................................................158

6.1.1

Project Management.................................................................................................158

6.1.2

Engineering...............................................................................................................158

6.1.3

Manufacturing ...........................................................................................................158

6.1.4

Installation .................................................................................................................159

6.1.5

Operations.................................................................................................................159

6.2

RISK MANAGEMENT .........................................................................................................160

6.2.1 6.3

Risk Analysis In The Project Phases........................................................................160

LESSONS LEARNED..........................................................................................................162



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1


INTRODUCTION

1.1

Scope

In deepwater field developments the great challenges are providing a stable platform on

Figure 1.1 - Subsea Production Systems Offer a Cost Competitive Option for Deepwater Field Developments which to mount the production facilities and transporting the production fluids to and from those facilities. Subsea production systems provide a cost competitive development option that lessens, or in some cases completely eliminates, the need for surface mounted production facilities. The scope of this study is to provide an overview of subsea production systems technology. Key topics to be covered include the following: • • • •

A general description of the main components of subsea production systems and their functions. Interface requirements for subsea production facilities. Overall field architecture considerations for subsea developments. Identification of areas of risk and risk management issues.



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1.2


Regulations, Codes and Standards

1.2.1 • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • • •

International Specifications ANSI B31.3, Chemical Plant Petroleum Refinery Piping. API RP 2R, Design, Rating and Testing of Marine Drilling Riser Couplings. API 5A, Specification for Casing, Tubing and Drill Pipe. API 5AC, Specification for Casing, Tubing and Drill Pipe. API 5D, Specification for Drill Pipe. API 5L, Specification for Line Pipe. API 6A, Specification for Wellhead and Christmas Tree Equipment. API 6D, Specification for Pipeline Valves. API 8A, Drilling and Production Hoisting Equipment. API 14A, Specification for Subsurface Safety Valves. API 14B, Recommended Practice for Design Installation & Operation of Subsurface Valve Systems. API 14D, Specification for Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Services. API 16A, Specification for Drill Through Equipment. API 17D, Specification for Subsea Wellhead and Christmas Tree Equipment. API 17G, Design and Operation of Completion / Workover Riser Systems ASME IX, Welding and Braising Qualifications, Article II Welding Procedure Qualifications and III Welding Performance Qualifications. ASME V, Boiler and Pressure Vessel Code Section V - Non Destructive Examination. ASME VIII, Boiler and Pressure Vessel Code Section VIII - Rules for Construction of Pressure Vessels - Division 1 & 2. ASME/ANSI B16.34, Valves - Flanged, Threaded, and Welding End. DIN 50049-EN 10 204, Documents on material tests. DnV Electrical requirements for WOCS DnV Safety and Reliability of Subsea Production systems DnV Cert. note 2.7-1 Lifting certificate requirements. ( Offshore containers ) DnV RPB401 Recommended Practice Cathodic Protection Design. EN 10204, Metallic Products - Types of Inspection Documents FEA-M 1990, Regulations for Electrical Installation on Maritime Platforms. IEC 92.101, Electrical Installations in Ships. Definitions and General Requirements ISO 10423, Specification for Wellhead and Christmas Tree Equipment (Replaces API 6A). ISO 10432 – 1, Standard for Subsurface Safety Valves. ISO 10433, Specification for Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service (Replaces API 14D). ISO 13628, Petroleum And Natural Gas Industries - Drilling And Production Equipment. ISO 13628-1, General Requirements And Recommendations. ISO 13628-2, Flexible Pipe Systems For Subsea And Marine Applications. ISO 13628-3, TFL Pump Down Systems. ISO 13628-4, Subsea Wellhead And Tree Equipment.



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• • • • • • • • • • • • •

1.2.2 • •

1.2.3


ISO 13628-5, Design And Operation Of Subsea Control Systems. ISO 13628-6, Subsea Production Control Systems. ISO 13628-7, Workover / Completion Riser Systems. ISO 13628-9, Remotely Operated Tools (ROT) Intervention Systems. ISO 14313, Specification for Pipeline Valves. Gate, Plug, Ball, and Check Valves (Replaces API 6D). ISO 3511, Process Measurement Control Functions And Instrumentation Symbolic Representation. ISO 898, Part I Bolts, Screws And Nuts. ISO 9001, Quality Systems: Model For Quality Assurance In Design/Development, Production, Installation And Servicing. NACE MR-01-75-94, Material Requirements, Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment. NACE RP0475, Materials For Water Injection. NAS 1638, National Aerospace Standard: Cleanliness Requirements Of Parts Used In Hydraulic Systems. SAE J343, Tests And Procedures For SAE 100R Series Hydraulic Hoses And Assemblies. SAE J517, Hydraulic Hoses.

UK Statutory Instruments SI. 913, Design and Construction Regulations. SI. 1019, UK. Statutory Instrument 1976 No.1019 for Offshore Installations stating Operational Safety, Health and Welfare Regulations.

NORSOK Standards

Norwegian Subsea Equipment is designed in accordance with the Norwegian Petroleum Directorate’s (NPD) regulations and the requirements in the following NORSOK specifications. The NORSOK standards have been developed by the Norwegian petroleum industry as a part of the NORSOK initiative and are jointly issued by OLF (The Norwegian Oil Industry Association) and TBL (Federation of Norwegian Engineering Industries). NORSOK standards are administered by NTS (Norwegian Technology Standards Institution). • • • • • • • • • • • •

1 U-DP-001, Principles for Design and Operation of Subsea Production Systems 2 U-CR-003, Subsea Christmas Tree Systems 3 U-CR-008, Subsea Color and Marking 4 M-DP-001, Material Selection 5 M-CR-101, Structural steel fabrication, Rev. 2, Jan. 1996 6 M-CR-120, Material data sheets for structural steel, Rev. 1, Dec. 1994 7 M-CR-501, Surface preparation and protective coating, Rev. 2, Jan. 1996 8 M-CR-503, Cathodic protection, Rev. 1, Dec. 1994 9 M-CR-505, Corrosion monitoring design, Rev. 1, Dec. 1994 10 M-CR-601, Welding and inspection of piping, Rev. 1, Dec. 1994 11 M-CR-621, GRP piping materials, Rev. 1, Dec. 1994 12 M-CR-630, Material data sheets for piping, Rev. 1, Dec. 1994



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• • • • •

1.3


13 M-CR-650, Qualification of manufacturers of special materials, Rev. 1, Dec. 1994 14 M-CR-701, Materials for well completion equipment, Rev. 1, Dec. 1994 15 M-CR-702, Drill string components, Rev. 1, Jan. 1996 16 M-CR-703, Casing and tubing materials, Rev. 1, Jan. 1996 M-CR-710, Qualification of non-metallic sealing materials and manufacturers, Rev. 1.

Definitions and Abbreviations

ADS: Annulus: BOP: Casing: Casing Program:

CDU:

Atmospheric Diving Suit The annular space between the production casing and the production tubing. Blowout Preventer Tubular steel conductors of progressively smaller sizes through which a well is drilled. The sequence of casing installed in a well. A common casing program is 30” (surface conductor), 20” (surface casing), 133/8” (intermediate casing) and 9-5/8” (production casing). Chemical (or Central) Distribution Unit

Completion Guidebase:

A permanent guidebase that incorporates production piping and flowline connections.

Concentric Tubing Hanger:

A tubing hanger with the production bore in the center and the annulus porting exiting the side.

COPS:

Communication On Power System

CRA:

Corrosion Resistant Alloy

DCS: Drill Through Wellhead:

Distributed Control System

DSV:

A subsea wellhead adapted for a mudline suspension system with a connection for a temporary tie-back casing to allow drilling with a surface BOP and later completion with a mudline tree. Downhole Safety Valve (See SCSSV)

Dual Bore Tree:

A subsea christmas tree with production and annulus bores passing vertically through the tree body.

EDU:

Electrical Distribution Unit

EFAT:

Extended Factory Acceptance Test

EFL: EPU:

Electrical Flying Lead Electrical Power Unit

ESD:

Emergency Shut Down

ESP:

Electric Submersible Pump

FAT: Flowbase:

Factory Acceptance Test See Completion Guidebase.

HCR:

High Collapse Resistance

HDM:

Hydraulic Distribution Module

Horizontal Tree:

A subsea christmas tree with production and annulus bores branching out horizontally through the side of the tree and the tubing hanger in the upper part of the tree.



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HPU:

Hydraulic Power Unit

Integral Valves:

ISU:

Valves machined from the single large “block” or forging that forms part of the subsea tree body, as opposed to “bolt-on” valves. Integrated Service Umbilical

IWOC:

Installation and Workover Controls.

JDT:

Jumper Deployment Tool

LIM:

Line Insulation Monitor Lower Marine Riser Package. A device similar to a small BOP attached to the tree mandrel used for emergency well control and riser disconnect when running, retrieving or working over a dual bore tree.

LMRP:

Low Pressure Housing:

The machined forged steel housing welded to the top of the surface conductor (usually 30”) into which the wellhead is fitted.

Marine Riser:

MASCOT:

A system used with floating offshore drilling rigs for guiding the drill string and circulating drilling fluids between the drilling rig and the subsea BOP. Module and Surface Computer Operations Tester

MCS:

Master Control Station

MMI:

Man Machine Interface

Mono-Bore Tree:

A subsea tree with the production bore passing vertically through the tree body and the annulus bore exiting through the side of the tree. Mudline Conversion System: A system of equipment by which a mudline suspension system may be converted to accept a mudline tree. Mudline Suspension System: A system for hanging casing at or below the mudline in offshore wells drilled using a surface BOP. Mudline Tree: A subsea christmas tree designed for installation on a mudline wellhead. Mudline Wellhead: A subsea wellhead used with a mudline suspension system. OS: Operator Station Pack-Off:

The system of seals installed in the casing hanger for sealing the annular space between successive strings of casing.

Permanent Guidebase (PGB): A fabricated steel structure attached to the low pressure housing for guiding equipment onto and into the wellhead by means of guideposts and guidewires to the surface. PLEM: Pipeline End Manifold. Production Casing: The final casing into which the production tubing is installed. Production Flowline:

The piping through which the production fluids are delivered from the production tree to the production processing facilities.

Production Platform:

For purposes of this Chapter, the term Production Platform means the host surface production facility that receives and processes the production fluids from the subsea wells. It could be a fixed platform, a jackup production platform, or a floating structure such as a spar, semi-submersible, TLP or FPSO.



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Production Riser:

The piping through which the production fluids are delivered from the sea floor to the surface production processing facilities.

Production String:

PVT:

See Production Tubing. The tubing through which the production fluids are delivered from the reservoir to the production tree. Pressure, Volume and Temperature

ROV:

Remotely Operated Vehicle.

SCM :

Subsea Control Module

SCMMB: SCMRT:

SCM Mounting Base Subsea Control Module Running Tool

SCSSV:

Surface Controlled Sub-Surface Safety Valve

Seal Assembly:

The annulus seal assembly. See Packoff.

SEM: SFL:

Subsea Electronics Module Steel Flying Lead

Side Valve Tree:

See Horizontal Tree.

Single Bore Tree:

Single-Bore™ Tree:

A subsea tree with the production bore passing vertically through the tree body and the annulus bore exiting through the side of the tree. A Dril-Quip mono-bore tree.

SIT:

System Integration Test

Production Tubing:

Subsea Production Manifold: A fabricated steel structure installed on the sea floor for production gathering, distribution and control. Subsea Production Template: A fabricated steel structure designed for supporting multiple subsea wells and associated piping and controls on one structure. Subsea Tree: A christmas tree designed for installation on a subsea wellhead. Subsea Wellhead: A machined, forged steel housing welded to the surface casing of a subsea well to which a BOP or a subsea tree may be connected for controlling the well and containing well pressures during drilling and production operations. Surface Conductor: The first casing installed for guiding the drill bit when a well is first started (usually 30”). It may be driven, jetted or drilled into place. Surface Tie-Back System: A system of special connectors and casing for extending the well casing from a mudline suspension system to a surface completion. TCU: Topside Control Unit Temporary Guidebase:

A fabricated steel structure with an opening and guide funnel at its center used for guiding the surface conductor into place when first starting a well, or for guiding the bit if the surface conductor is to be drilled into place.

TEPU:

Test Electrical Power Unit A specialized well workover system using special tools designed to be pumped through the production flowline and down the production tubing.

TFL (Through Flowline):



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Through-Bore Tree: Tree Connector:

Tree Mandrel:

Tree Running Tool:

Tubing Hanger:


A subsea tree with the production bore passing vertically through the tree body and the tubing hanger in the tree body. The mechanism at the base of the tree that connects the tree to the wellhead by means of a hydraulic or mechanical actuator. See Wellhead Connector. A machined hub at the top of a dual bore subsea tree for connection of the tree running tool or the LMRP and gaining access to the tree bore. A specially designed tool used for lowering the subsea tree onto the wellhead and actuating the tree connector or, inversely, for removing the tree from the wellhead. For dual bore trees it is sometimes incorporated into the LMRP.

TUTA:

A component of the wellhead system for supporting the production tubing in the well and aligning the production and annulus bores with the BOP or subsea tree. A term sometimes used for a wellhead with a tubing hanger but no casing hangers. See Mudline Wellhead. A wellhead adapter for 1) converting from a wellhead of one profile type to another or 2) providing a new wellhead seal surface if the original one is damaged. Topside Umbilical Termination Assembly

TUTB:

Topside Umbilical Termination Box

UJB:

Umbilical Junction Box

UPS: USV:

Uninterruptible Power Supply Upper Swab Valve

UTA:

Umbilical Termination Assembly.

UTH:

Umbilical Termination Head

VSE:

Valve Signature Emulator A mechanism for connecting other equipment to a wellhead by engaging and locking onto the wellhead profile. See Tree Connector.

Tubing Head: Tubing Spool Adapter:

Wellhead Connector:

Wellhead Profile:


The external machined profile at the top of the wellhead that provides a load bearing shoulder and seal surface for the BOP connector or the tree connector.


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2


SUBSEA PRODUCTION EQUIPMENT

2.1

Introduction

As subsea production equipment has proven its reliability in service and as its cost, in relative terms, has fallen, the oil industry has come to accept it as a technically viable and competitive field development option. Subsea production equipment here is meant to include subsea wellheads, subsea production trees, subsea manifolds, subsea well templates and the ancillary equipment associated with these.

Figure 2.1 - A Variety Of Field Development Options Exist as Subsea Technology Moves Into Deeper Waters. The focus for this discussion is deepwater developments. The term “deepwater” is subject to interpretation, but in general one can assume it to be beyond the reach of current saturation diving technology. Subsea developments within diver accessible depth are so routine as not to merit much comment these days. For this discussion we are assuming deepwater to begin at water depths well beyond the practical range of saturation diving, within the reach of current generation ADS equipment and extending to depths that require methods other than human intervention, such as remote control or ROV intervention. This covers a range of roughly 300 to 2500 meters. It should be noted that 2000 to 2500 meters represents the approximate limit of current well completion experience, although exploration drilling activity continues to push into deeper waters.



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2.2


Subsea Wellheads

2.2.1

Functions of Subsea Wellheads

Drilling a subsea well from a floating drilling rig or completing a well subsea requires a subsea wellhead. Subsea wellheads serve several purposes: • • • •

to support the subsea blowout preventer (BOP) and seal the well casing during drilling to support and seal the subsea production tree to support and seal the well casing. to support and seal the production tubing hanger.

Figure 2.2 - A Typical BOP Stack Being Deployed



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The subsea wellhead together with the BOP or the production tree provides the means to safely contain reservoir pressure during oil and gas drilling and production operations. It rarely sees actual reservoir pressure but is rated to withstand this pressure in case of loss of well control during drilling or a breach of a primary pressure barrier during production. Standard API pressure ratings in use are 5,000 psi, 10,000 psi, 15,000 psi. and more recently 20,000 psi. The subsea wellhead may also be designed to accommodate a surface tie back system to a surface completion on a TLP, spar or, more rarely, a fixed platform.

2.2.2

Types of Subsea Production Wellheads

The term “subsea wellhead”, for the sake of this discussion, describes a specific class of wellhead used in subsea drilling applications that require installing the BOP at the seabed. It is sometimes also referred to as a marine wellhead. Subsea wellheads are typically used for drilling wells from a floating drilling rig. Another class of wellheads that is sometimes employed on subsea production systems is the mudline suspension system. The mudline suspension system relies on the use of a surface BOP during drilling, usually from a jackup type drilling rig. Subsea wellhead designs have evolved along with advances in subsea drilling and well completion technology. Subsea wellheads generally come in one of the following sizes: • • • •

13-5/8 inch 16-3/4 inch 18-3/4 inch 21-1/4 inch

The size designates the nominal bore (I.D.) of the wellhead, in inches. The 18-3/4 inch subsea wellhead is currently the most common. Earlier subsea drilling systems used a “two stack” approach and relied on a low-pressure 21-1/4 inch BOP to start the well and a high pressure 13-5/8 inch BOP for finishing the well. With the development of the 18-3/4 inch x 10,000 psi (10M) BOP, the well could be drilled to final depth with one BOP and the 18-3/4 inch x 10M wellhead became the standard. Wellhead pressure ratings are trending higher, with 18-3/4 inch x 15M wellheads becoming the new standard, though manufacturers still offer 10M models. 18-3/4 inch x 15M BOPs are not as common, but the 15M wellheads are compatible with the 10M BOP connectors. Traditionally Drill Ships have used 16-¾ inch subsea wellhead systems. The advantage of the 16-¾ inch wellhead is smaller riser and less mud volume. Riser storage requirements are reduced, the suspended weight is reduced, current drag on the riser is reduced, and the mud system can be smaller. The 16-¾ inch wellhead systems are relatively common in Brazil, probably influenced by their significant deepwater experience and prevailing available equipment at the time that trends were established. An area for further development by wellhead manufacturers is in smaller bore versions of current wellhead and tree technology. This would help mitigate the increased weight imposed by deeper water operations. Manufacturers of Subsea Intervention Trees are being pressured to provide higher pressure rated designs for use within smaller (16-¾ inch) bores. Operators may adopt Slim Hole well technology that starts with 26-inch conductors.



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2.2.3


Wellhead Connector Profiles

All subsea wellheads have an external profile for mechanically connecting and sealing the BOP or tree to the wellhead. There are numerous profiles available today, with most manufacturers having their own proprietary designs. The Cameron ”hub” and Vetco H4 “mandrel” profiles are most common. Through cooperative licensing arrangements with their competitors, wellhead manufacturers are able to provide wellheads with different profile choices for their customers, within limits. Each wellhead profile utilizes a particular style of metal gasket designated “AX”, “DX”, “VX”, or “NX” depending on the wellhead profile. The gasket provides the seal between the wellhead and the BOP connector. It is the ultimate barrier between the well and the environment.

Wellhead Datum

Wellhead Profile

Wellhead Datum Internal Profile Datum

Figure 2.3 - Wellhead Profiles. The two most common external wellhead profiles are show in this diagram – the upper figure shows a typical Vetco H-4 (Mandrel) profile and the lower figure shows a typical Cameron (Hub) profile. Interface features are also identified –note especially the datum line– used for all height measurements. Deepwater profiles are now becoming more commonplace. These were developed for much higher bending and tension loads that can be experienced in deeper water depths. Cameron has developed the double hub style profile. This profile is unique in that either their new deepwater connector or their standard connector can latch onto it. ABB Vetco Gray has also developed a deepwater profile and wellhead. It is similar to their existing designs except that the wellhead wall thickness is greater and the outer profile diameter is larger providing more strength than their conventional wellheads. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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2.2.4


Tubing Spool Adapters

It is necessary that the wellhead connector on the BOP be compatible with the wellhead on the planned development well. Fortunately BOP wellhead connectors can be changed out relatively easily. Operators may therefore specify the wellhead type and profile of choice, taking into account compatibility with other existing wells or their preference for the well completion equipment. If an operator wishes to complete a well with a tree having a connector that is not compatible with the wellhead, a wellhead conversion can be installed. This wellhead conversion is called a tubing spool adapter, and consists of a forged spool piece having a connector matching the existing wellhead on the bottom and a profile matching that of the tree’s connector on top. These conversions are sometimes referred to as tubing head adapters. A tubing spool adapter can also used to provide a new wellhead seal surface if the existing one is damaged. This is not an uncommon occurrence with exploration wells that are ultimately completed and turned into production wells. They can also be used to land the tubing hanger into, and this is often done for conventional style trees.

2.2.5

Casing and Tubing Hanger Interface

2.2.5.1 Typical Well Casing Programs Depending on the soil conditions the hole may be started with a large conductor such as 42 inch or 36 inch or, if a template is being used it may have a large sleeve pre-installed. Then a conventional 30 inch conductor is usually installed. Again depending on the anticipated loading this may have a 1 inch, 1-1/2 inch, 2 inch, or larger wall thickness. Most subsea wells are started by driving, drilling or jetting-in the ‘surface’ conductor with the low-pressure housing attached to the top. The well is then drilled ahead through this conductor. The 18-¾ inch high-pressure wellhead (housing) with 20 inch/18-¾ inch or similar sized casing attached is then run through it, into the pre-drilled hole, landed in the low pressure housing and cemented in place. The subsea BOP stack is then run onto and tested on the high-pressure wellhead housing. Further holes are progressively drilled ahead and the appropriate sized casing is then installed through the BOP and wellhead. These are selected from a variety of sizes. The following sizes are the most common; 20 inch, 18-¾ inch, 16-¾ inch, 13-3/8 inch, 10-¾ inch, 9-5/8 inch and 7 inch. The progressively smaller selected casings are suspended in the wellhead. Most wellheads can accommodate 3 or 4 hangers. If more casing is required, it can be suspended farther down the well bore as a ‘Liner’. Horizontal subsea Christmas trees, described elsewhere in this chapter, enable the wellhead system to have one less hanger than conventional trees normally demand of wellhead systems because the tubing hanger sits in the horizontal tree rather than the wellhead as in a conventional tree. It is still routine practice to include an extra hanger slot available in the wellhead ‘just in case’. Tubing hanger adapter spools can be added above the wellhead to accommodate the tubing hanger and although rarely done, more casing hangers if required. Figure 2-10 illustrates an 18-3/4 inch wellhead with two casing hangers installed. Most wellheads are limited to 3 or 4 hangers. If more are required, secondary hangers can be installed below the wellhead. Packoffs or seal assemblies in the wellhead seal the annulus between casings. Older packoff designs used elastomer seals. Newer designs employ metal to metal seals. These are, in some cases, actually composite metal and elastomeric seals designed so that the elastomer



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provides an initial seal that, with deformation, causes the metal seal to be forced into place or ‘energized’. The elastomer serves as a back-up seal. Most of the casing weight is suspended at the mud line by the wellhead. Some casing strings are anchored deeper in the well. Later when the production tubing is installed, it is suspended either in the wellhead or tubing hanger adapter spool or in the tree above. Each method transfer the loads back to the wellhead. During well production thermal and pressure effects on the tubulars can reverse the hanger loads and push up against the wellhead. Therefore lock down of the hangers is recommended for production wells. Some ‘Exploration’ wellheads do not apply the lockdown feature so as to facilitate dismantling and abandonment of the well and because this feature can sometimes be troublesome to install.

Figure 2.4 - Typical 13-3/8” Casing Hanger

2.2.5.2 Casing Hanger At the top of each casing (and the production tubing) is a forging with an external, tapered shoulder that lands on a mating shoulder within the wellhead and transfers the weight of the casing to the wellhead. These supporting shoulders are called Hangers. There are different designs of hangers for suspending casing or production tubing. The casing hanger also provides a machined surface to seal against. Once the casing is landed and locked in place, the annular cavity is sealed by a Pack-Off or seal assembly mechanism.



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2.2.6


Wellhead Guide Structures

2.2.6.1 Guideline Drilling and Completions Most subsea wells employ the use of a permanent guide base (PGB) mounted to the low pressure conductor housing. The PGB is a fabricated structure with guideposts and wire rope guidelines for guiding equipment onto or into the wellhead, or it may be a guidelineless style, which employ large funnels for guidance.

Figure 2.5 - A Typical Temporary Guide Base

The nomenclature “permanent” is used to distinguish it from the “temporary” guide base (TGB), at one time traditionally used for starting the well, although modern equipment has made the TGB largely unnecessary. The TGB is typically a gravity-stabilized guide structure normally with a 42 - 46 inch diameter central hole that is lowered to the seabed on four guide wires. The TGB lies on bottom at the angle of the seabed and holds the guide wires in place

Figure 2.6 - A Temporary Guide Base Being Deployed by a Running Tool on Drill Pipe to enable the 30-inch conductor to be easily guided through the central hole. The housing at the top of the 30 inch has the PGB attached to it, to take over the guidance function after the 30 inch conductor has been secured. The term “temporary” in the name is misleading in that it is a permanent fixture to the well once deployed. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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PGBs normally incorporate level indicators that can be observed by camera when landing the first conductor in a new well. If the conductor is off true vertical by more than about one degree, the driller may decide to re-spud the well. It is recommended almost universally to do this if the well is off vertical by more than one degree. If not, key seating (wearing on one side) of the casing and or BOP stack can occur seriously degrading the pressure integrity of the well and well control equipment. The guideposts are normally designed to accommodate guide wires latched to the post tops. The post tops are generally designed to enable easy latching or unlatching of the guide wires and include a means of reestablishing new guide wires onto the post top. Virtually all PGBs utilize the API standard post spacing, four guideposts at 90º spacing, on a six-foot radius from the well center. This leads to the standard 101.82 inches between posts.

Figure 2.7 - Example of a Retrievable Permanent Guide Base PGBs can be designed to be retrievable while leaving the well intact for future use. This offers the advantage of not having to purchase a new guide base for every well. This style of guide base is more expensive than one that is not retrievable, but pays for itself after use on very few wells. These types of PGBs are often referred to as RGBs – Retrievable Guide Bases. If it is known beforehand that the well is to be a production well, the guide base may incorporate piping, flowline connections, and tree piping interface hardware. This type of guide base is generally referred to as a completion guide base (CGB), or a flowbase. Virtually all CGBs are application specific designs. Sometimes a CGB is deployed on top of an existing PGB if it cannot be easily removed.

2.2.6.2 Guidelineless Drilling and Completions Guidelineless PGBs are used in deeper water where guidelines become cumbersome and less effective. They are usually deployed from dynamically positioned drilling vessels. They can be used at shallow depths but are not normally used in less than about 2,000 feet. They typically have a funnel-up design for capturing the guidelineless BOP or subsea tree and guiding it onto the wellhead. Guidelineless funnel-down trees are sometimes used to complete wells in shallow water that have no installed guidebase. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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2.2.7


Loads on Wellheads

Wellheads must be designed for high structural loads imposed during drilling, workover, or well completion operations. The wellhead must support the weight of the BOP, drilling riser loads, casing weight and forces imposed by internal pressure. In general, wellheads are of such robust construction that, as far as external loads are concerned, they are rarely the weak point of the wellhead system. The 15M wellheads can generally sustain greater external loads than the 10M wellheads. For deep water and other special applications, manufacturers must engineer the wellhead equipment to meet the specified load requirements. A heavy duty deepwater wellhead with a heavy duty connector engaging two profiles instead of the one for more strength is shown in Figure 2-11. To improve the transfer of loads from the wellhead to the low-pressure conductor housing and reduce fatigue stresses and fretting at critical wellhead interfaces, a rigid lockdown system may be employed. This mechanism locks the wellhead housing securely into the lowpressure conductor housing. It may be engaged automatically with the installation of the wellhead (passive), or it may require an externally applied preload (active).

2.2.8

Subsea Wellhead Materials

The following is a list of typical materials used for main components in a subsea wellhead system.

2.2.9

COMPONENT

MATERIAL

Low Pressure Conductor Housing Conductor Pipe 18 3/4 inch Wellhead Housing Wellhead Seal Area 20 inch Casing Extension, Wellhead Lock Ring Casing Hangers Pack-Off Seal Elements Pack-Off Bodies Pack-Off Split Rings

AISI 8630 Modified. API 5L X52 AISI 8630 Modified, 80 Ksi. Yield Inconel 625 Overlay API 5L X52 AISI 4140/4145, 105 Ksi. Yield AISI 8630 Modified, 80 Ksi. Yield AISI 1010 or 1015 AISI 4140, 75 Ksi. Yield 17-4 PH, 100 Ksi. Yield

Description of Typical Subsea Wellhead System

For the purposes of this discussion, a wellhead system consisting of the following components will be considered: • • • • •

30 inch conductor housing joint, 18 ¾ inch wellhead housing joint, 20 inch casing 13 3/8 inch and 9-5/8 inch centralized casing hangers Associated packoffs.



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2.2.9.1 Subsea Wellhead Features: The following are features that should generally be expected in wellhead equipment: • • • • • • • • •

The ability to test all the seals and locking arrangements. Protection for all permanent seals during running and the seals are remotely energized after landing. The ability to clean component seal surfaces after cementing operations and prior to setting the pack off seals. The casing hangers have ability to be locked in place. The flow path for cuttings and cement returns without excessive build up of pressure, blockage or reduction in velocity through the flow-by holes and slots. The use of a minimum number of seals and components installed subsea. The primary metal-to-metal seals with elastomeric secondary system for all permanently installed seals. Weld overlay surfaces with a nickel-based alloy (Inconel 625) at the wellhead's gasket seal surface. Reliable and robust suite of versatile running tools.

2.2.9.2 30 inch Conductor Housing Joint. The 30-inch conductor-housing joint provides the structural foundation for the wellhead system. The outer diameter of the housing is fitted with a keyway and a shoulder to provide orientation of the PGB which in turn orientates the BOP and the tubing hanger, and later the

Figure 2.8 - Typical 30” Wellhead Housing tree. The joint generally consists of a 30 inch conductor housing welded onto a 30 inch conductor pipe. A proprietary, mechanical, pin connector is fabricated onto the bottom end of the 30-inch conductor. The overall length of the joint is approximately 45 feet. The 30-inch conductor will normally have large landing pad eyes for handling and hang off purposes welded to it near the housing. The string is suspended below the pad eyes through the rotary Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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table while the running tool is made up to it. The padeyes are then cut or burnt off and the casing run to the seabed. A 30-inch conductor housing should normally provide the following features: • • • • •

An internal profile locking facility for the 30-inch conductor housing running tool. Side outlet holes with diameters for cement returns. Control of the elevation, concentricity, and vertical alignment of the 18-3/4-inch wellhead housing by the load shoulder and locking mechanism incorporated with the internal profile. Unrestricted passage of a 26-inch drill bit. Available working pressure of 2000 psi (135 bar).

2.2.9.3 18-3/4 inch Wellhead Housing Joint. The 18-3/4 inch wellhead housing joint serves as the suspension head for the surface casing string and provides a mechanical connection and sealing preparation for the BOP stack and tree. It also provides landing, locking, and sealing preparations for the subsequently run

Figure 2.9 - Typical 18-3/4” Wellhead Housing casing hangers. The 18-3/4 inch wellhead housing joint generally consists of an 18-3/4 inch high pressure housing welded to a 20 OD pipe (typically 0.625 inches wall thickness). A 20 inch pin connector is welded to the lower end of the casing joint. The overall length of the 183 /4 inch wellhead housing joint is approximately 40 feet.



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An 18-3/4 inch wellhead housing should generally provide the following features: • • • • •

Positive mechanical lockdown mechanism into the 30 inch conductor housing. Provision for the flow of drill cuttings and cement returns between the 18-3/4 inch wellhead and the 30-inch conductor housing. Control of the elevation and concentricity of the casing hangers and the tubing hanger. Seal surfaces appropriate for the sealing systems associated with the test and running tools. Transfer loads from the hangers and bending loads from the BOP and riser into the 30 inch conductor housing. This can be achieved by a two point socketing arrangement between the 30 inch housing and the 18-¾ inch wellhead housing.

Profile

Wellhead Wear Bushing

Pack Offs or Seal Assemblies

Casing Hangers

Figure 2.10 - A Typical Modern Wellhead Stack-Up • • • • •

Allow passage of 17-1/2 inch drill bit. Incorporates an external wellhead connector profile to suit the tree connector and BOP connector. A wellhead gasket seal preparation for metal-to-metal sealing between the wellhead and the connector, inlaid with nickel based alloy Inconel 625. Suitable working pressure of 10,000 or 15,000 psi A variety of profiles exist in the market today. There are two primary profiles, licensed by two different manufacturers. All manufacturers produce each other’s profiles



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through cooperative agreements and license arrangements. The two most common profiles are currently being further developed for deep water requirements demanding higher capacities.

HC CONNECTOR ON DWHC HUB DWHC Connector on Standard Hub DWHC Connector on DWHC Hub Figure 2.11 - One Manufacturer’s Standard (HC) and Deepwater (DWHC) Wellhead Connectors on Standard and Deepwater Wellhead Hubs, Demonstrating Their Interconnectability

2.2.9.4 The Casing Hangers The casing hangers centralize and suspend the casing strings inside the 18 3/4 inch wellhead housing. They also provide seal surfaces for the pack off assembly to isolate the casing annuli. The casing hangers are normally supplied with a casing pup joint pre-installed. The casing pup usually terminates with a pin connection. • • • • • • •

Casing hangers should generally provide the following additional features: Two-point centralization in the 18-3/4 inch wellhead housing. Sufficient flow-by area to permit flow of drilling mud, cuttings, and cement. Allows passage of drill bits for the next successive casing size. Interfaces with a variety of running tools – such as drill pipe tool, full bore tool, or single trip tool. Suitable working pressure of 10,000 or 15,000 psi. Suspend a sufficient working load – usually at least 1,000,000 lbs capacity.



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2.2.9.5 Pack-Off (Seal) Assembly. The pack off or seal assembly should generally provide the following features: • • • • • • •

The necessary seals and components to ensure that the seal is set, energized, tested and if required, retrieved in a single down hole trip. Seals are protected during running phase. Single trip tool runs casing hanger and pack off assembly as a unit. Complete seal assembly can be retrieved using single trip tool or a pack off retrieval tool. An effective seal for continuous or intermittent annulus pressure. Bi-directional metal-to-metal seal with elastomeric backup seals to pack off the casing hanger to 18 3/4 inch wellhead housing annulus. Suitable working pressure of 10,000 or 15,000 psi.

Figure 2.12 - Typical Casing Hanger for Subsea Wellhead



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2.2.10 Wellhead Running Tools Running tools are required to install, test and retrieve the wellhead system components. These tools are supplied by the wellhead manufacturer as part of the wellhead system, most often on a rental basis. One aspect of wellhead system design is to design the running sequence and tools so as to minimize the number of trips required. This becomes more important in deep water where rig rates are high and trips take more time. The tools should be of robust design, debris tolerant, and capable of giving strong easily detected signals of correct function that can be observed at the drill floor.

Figure 2.13 - A Typical Suite of Subsea Wellhead Running Tools



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2.2.10.1 Bore Protector The bore protector is used to protect the casing hanger sealing surfaces inside the 18 3/4 inch wellhead housing during drilling operations associated with the subsequent setting of the surface casing string. The wellhead housing can usually be deployed with the bore protector installed. Additionally, most systems have tools designed that do not transfer pressure end load into the protector and therefore allow the BOP stack to be pressure tested without retrieving the bore protector. The bore protector is normally mechanically held in place by shear pins or o-ring friction.

2.2.10.2 Wear Bushing. The wear bushing protects the bore of the packoffs and casing hangers from mechanical wear associated with drilling activities subsequent to the setting of the intermediate casing string. It is deployed and retrieved on drill pipe and set using a wear bushing running and retrieval tool. These are often used for several functions and called multi-purpose or multiutility tools. The wear bushings are normally designed to allow BOP testing to be conducted without retrieving the bushing.

Figure 2.14 - A Typical 30” Wellhead Running Tool



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2.2.10.3 30-Inch Conductor Housing Running Tool. The 30 inch running tool is used to deploy the 30 inch conductor string and housing. Typical features of this tool are: • • • • • • •

Locks into the profile of the 30 inch housing. Seals inside the 30 inch housing below the flow-by ports Visual position indicator provided. Anti-rotation feature. Right hand rotation of the running string releases the tool. This is often a hydraulic function in deeper waters. 6 5/8 inch API Regular box up by 4 1/2 inch API Internally Flush (NC50) pin down. Valves to allow filling of the string with seawater and then closed.

2.2.10.4 18 3/4 inch Housing Running Tool. The 18 3/4 inch housing running tool runs the high-pressure wellhead housing. It typically includes the following features: • • •

Locks into the upper groove inside the wellhead bore. Has visual position indicator. Right hand rotation of the running string to release. This is often a hydraulic function in deeper waters.

Figure 2.15 - A Typical 18-3/4” Wellhead Running Tool • • •

6 5/8 inch API regular box up by 4 1/2 inch API Internally Flush (NC50) box down. Anti-rotation pins to prevent free spinning of the tool inside the housing. Valves to allow filling of the string with seawater and then closed.



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2.2.10.5 Bore Protector Running and Retrieval Tool. A Bore Protector Running and Retrieval Tool is typically used for running and retrieving all of the 18-3/4 inch bore protectors and wear bushings. It can also be used as a test tool with wear bushings in place or as a washout tool if need be. The tool typically has a 4-1/2 inch API Internally Flush (NC50). box up by 4-1/2 inch API Internally Flush (NC50) pin down.

2.2.10.6 Single-Trip Tool Most wellheads have a single trip tool available which is used to run, set, and test the casing hangers with its pack off in a single trip. After the casing is cemented in place, the tool hydraulically sets the pack off. Most tools are designed so that if the pack off should fail to set properly, the tool will retrieve it. The tool generally has a 6-5/8 inch reg. box up by 4 1/2 inch API I.F. pin down.

Figure 2.16 - A Typical 18-3/4” BOP Test Tool



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2.2.10.7 Pack-Off Assembly Running Tool The Pack-Off Assembly Running Tool is primarily used to run, set, or retrieve the pack off independently of the casing hanger. It will typically enable testing of the pack off in the same running trip. The tool typically has a 4-1/2 inch API Internally Flush (NC50)inch box up by 41/2 inch API IF (NC 50) box down.

2.2.10.8 Drill Pipe Casing Hanger Running Tool. The casing hanger running tool runs the casing hanger without its packoff on drill pipe. Running the casing hanger and pack off this way is a two-trip operation and in deeper waters is generally avoided.

2.2.10.9 Full Bore Casing Hanger Running Tool. The casing hanger running tool runs the casing hanger without its packoff on casing. Running the casing hanger and pack off this way is a two-trip operation and in deeper waters is generally avoided.

2.2.10.10 BOP Test Tool. The BOP test tool is used to test the BOP stack without subjecting the wellhead components below it to the BOP test pressure. The tool is deployed on drill pipe and seals inside the housing bore.

2.2.10.11 Emergency Drill Pipe Hang-Off Tool. The emergency drill pipe hang off tool is used to suspend drill pipe in the wellhead during suspended drilling situations. Drill pipe weight is transferred into the wear bushing. The configuration of the tool is unique to the particular BOP stack involved in the field development.

2.2.10.12 Mill and Flush Tool. The mill and flush tool is primarily used to clean out the annular area behind the casing hanger neck before the installation of the pack off assembly. Lead impression blocks can be provided to enable the elevation of the casing hanger to be verified prior to running the pack off.

2.2.10.13 Emergency Seal Assembly. The emergency seal assembly is used when the casing hanger is set high. Height adjustment is built into the design of the emergency seal assembly enabling it to pack off on the high set, casing hanger. It can then still provide a landing shoulder for the subsequent run casing hanger or seal surface for the Horizontal Tree stinger at the correct elevation.



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2.2.11 Typical Subsea Wellhead Installation Procedures • • • • •

• • • • • • • • • • • • • •

Run 30 inch conductor string into open hole with 30 inch suspension joint attached to the guidance cone. Once landed and set to the correct vertical elevation, cement 30 inch conductor in place according to operator procedures. Rotate the drill pipe and pull to release running tool. Pull back to surface. Drill the next hole to TD and run the 20-inch casing. Attach the 18 ¾ inch wellhead body to the 20-inch casing. Install the bore protector in the wellhead (if not installed at the factory). Run cement stinger into wellhead housing sitting on rotary table and make up the wellhead body to the running tool. Make up running tool to wellhead. Run the wellhead body assembly into the suspension joint. Cement. Release the running string from the wellhead by rotation and pull back to surface. Place the drilling BOP across the spider beams over the moon pool. Make up the hydraulic umbilicals and check all the functions. Run the BOP on marine riser. Lock BOP connector onto 18 ¾ inch wellhead. Rig up diverter with choke and kill lines. Make up the isolation test tool onto drill pipe string. Run into the wellhead. Test the BOP stack then retrieve the test tool. Drill the hole for the 13-3/8 inch casing. Pull back the string and make it up to the bore protector retrieval tool. Run in and retrieve the bore protector. Run in the 13-3/8 inch casing string with attached cementing equipment. Make up the 13-3/8 inch casing hanger and the pack off to the single trip tool and make this assembly up to the casing string, run in the hole with the drill string and casing. Land the hanger into the 18 ¾ inch wellhead. Slack off the weight and cement the string into place. Activate the pack off setting mode of the tool Slack off the string weight and close the BOP pipe rams. Build up pressure above the tool to set and test the pack off. Open the pipe rams, release the tool from the pack off and then pull it back to the surface. Run in the 13-3/8 inch bore protector on the bore protector running tool. Land and lock into the wellhead. Release the tool and pull back to the surface. Repeat the above steps to run the next casing strings. Start next functions for well – (e.g. Temporary abandonment, permanent abandonment, completion, etc.).



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2.3


Subsea Christmas Trees

2.3.1

Functions of Subsea Trees

A subsea Christmas tree is basically a stack of valves installed on a subsea wellhead to provide a controllable interface between the well and the production facilities. Some specific functions of a subsea Christmas tree include the following: • • • • • • • •

Sealing the wellhead from the environment by means of the tree connector. Sealing the production bore and annulus from the environment. Providing a controlled flow path from the production tubing, through the tree to the production flow line. Well flow control can be provided by means of tree valves and/or a tree-mounted choke. Providing access to the well bore via tree caps and/or swab valves. Providing access to the annulus for well control, pressure monitoring, gas lift, etc. Providing a hydraulic interface for the down hole safety valve. Providing an electrical interface for down hole instrumentation, electric submersible pumps, etc. Providing structural support for flow line and control umbilical interface.

Figure 2.17 - Schematic Representations of Different Tree Types Tree


Tubing Head Spool

Tubing Hanger


Subsea Wellhead

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2.3.2


Types of Subsea Trees

2.3.2.1 Dual Bore Tree or Conventional Tree Until recently, most subsea trees were so-called “dual bore” type trees. A typical dual bore tree is illustrated in Figure 2-18. These trees have a production and annulus bore passing vertically through the tree body with production and annulus master valves and swab valves oriented vertically in the main block of the tree. They are designed to allow vertical access to the main production bore and to the annulus bore during installation and workover operations. When a dual bore subsea Christmas tree is connected to a subsea wellhead it must interface with the tubing hanger previously installed in the wellhead. The tubing hanger and tree must

Figure 2.18 - Example of a Compact Dual Bore Tree be correctly orientated so they mate properly with one another and the production and annulus bores are properly aligned and sealed. Alignment of the tubing hanger in the wellhead is generally accomplished by interaction of a pin and helix between the tubing hanger running tool and the BOP or a pre-machined vertical orientation slot in the BOP connector upper body. The reaction between the pin and the helix causes the tubing hanger assembly to rotate into the correct position. Alternatively, the tubing hanger is rotated until the alignment slot lines up with a spring-loaded alignment key on the running tool. The tree is subsequently aligned by the permanent guidebase.

2.3.2.2 Mono Bore Tree A typical mono bore tree is similar to a conventional dual bore tree but differs in that it utilizes a simpler riser system to install the tree and tubing hanger. Additionally simpler styles of mono bore tree exist which are generally used on mud line completions in shallow water. When producing a well, the annulus between the production tubing and the well casing must be accessible to relieve thermally induced pressure build up. In order to accomplish this, tubing hanger and tree systems must enable access to the annulus under the tubing hanger. Both conventional and mono-bore trees (except the basic mudline style trees) utilize a port Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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through the tubing hanger. This port, as well as the production bore, must be closed before removing the BOP or the subsea tree. On a conventional style tree, the annulus port is typically sealed with a wire line plug run and retrieved through a multi-bore completion riser or a riser with a diverter mechanism. This riser is generally expensive and dedicated to the tree system. Refer to descriptions of riser systems elsewhere in this document for detailed descriptions. In the mono bore tree system the tubing hanger is run on drill pipe or tubing and the annulus is accessed through a hose bundle. Opening and closing of the annulus is accomplished by means of a “shiftable” plug or valve in the annulus bore. The disadvantage to this, as compared to the dual bore system, is the requirement for moving parts within the tubing hanger that must be left subsea for the life of the completion. Some designs incorporate a second plug or valve, ported in series with the primary plug, which can be actuated as a backup to close the annulus if more redundancy is desired. The mono bore tree obviates the need for a true vertical annulus bore through the tree.

Figure 2.19 - Deepwater Guidelineless Horizontal Tree

Figure 2.20 - Monobore Tree

2.3.2.3 Horizontal Tree Another type of subsea Christmas tree that has gained popularity since its introduction in 1992 is the “horizontal” tree. A typical horizontal subsea trees are illustrated in Figures 2-19 and 2-21. Its most obvious distinction from the dual bore tree is that the production and annulus bores branch horizontally out of the side of the tree body and the valves are oriented on a horizontal axis. The horizontal tree has no production or annulus swab valves. Access to the well bore is gained by removing the internal tree cap, or a wireline plug within the internal tree cap, and a wireline plug in the tubing hanger. The horizontal subsea Christmas tree is sometimes referred to as a “side valve tree” or SpoolTree™. Other distinguishing features of the horizontal tree, in addition to the valve arrangement from which it gets its Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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name, are: 1) the tubing hanger is installed in the tree itself, rather than in the wellhead and 2) the top of the tree is designed so the BOP may be landed onto the tree. This arrangement allows the tubing string to be recovered without first retrieving the tree. Horizontal Tree technology was conceived and developed to run and retrieve well bore tubing through an installed tree providing a simple and efficient work-over capability. Originally, this type of technology seemed ideally suited for Electric Submersible Pump (ESP) applications, where frequent pump maintenance or replacement may be required. Well interventions were most commonly caused by the need to repair downhole problems as opposed to subsea tree equipment problems. The concept was extended to include standard production and injection wells in the belief that horizontal technology offered much greater benefit over conventional technology, at least in some applications. The benefits and drawbacks of both horizontal and conventional tree technologies have been the subject of many debates for several years. The newer horizontal tree technology has been shown to have significant merit in order to have acquired at least 50 % of the market in less than six years. It is probable that both completion technologies will have a vital part to play in future oil and gas developments and the possibility of a winner for all applications is unlikely.

Figure 2.21 - Horizontal Trees



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2.3.2.4 ADVANTAGES of Horizontal Trees • Tubing recovery is simplified. The ability to perform tubing work-over and some drillthrough operations without the need to recover the subsea tree and disturb the associated production flowline/controls connection is beneficial. This is particularly attractive for wells with planned or scheduled tubing work-over intervention or complex down-hole completions with the higher probabilities for down-hole failures requiring rig intervention. • The spool tree is suitable for tubing up to 7” OD whereas the dual bore tree is limited to 5-1/2” OD. The larger bore can also accommodate a larger number of down-hole hydraulic control lines, chemical lines and electrical transducer penetrations with the capability to provide full bore annulus circulation or injection. • The large bores possible with this system are consistent with the usual objective to reduce the number of wells. However, reliability may be compromised by a more complex completion. • The ability to use standard, drilling BOP stacks for installation and work-over. All the completion operations except for running the subsea tree and debris cap are performed through the drilling BOP stack. This eliminates the need for a dedicated open water completion riser system. • All completion work is carried out through or within the protection of a BOP stack. • The ability to use single string tubing or casing as an installation and completion riser allows a cheaper riser to be configured than a conventional dual bore riser. The BOP stack’s choke and kill lines are used to circulate the annulus or riser fluids prior to disconnection and recovery of the riser system. The production tubing annulus access bypasses the tubing hanger and uses metal sealing valves for annulus isolation. This provides maximum space through the tubing hanger body for big bore completions. • Subsea tree installation or recovery is greatly simplified by using drill pipe instead of a dedicated riser system. • The Subsea Tree provides an integral and precise, passive tubing hanger orientation system with no requirement for BOP modifications, interaction or datum’s. • Subsea tree provides new, exact and retrievable tubing hanger landing, locking, orientation and sealing profiles, not dependent on the condition of wellhead internal profiles. A damaged hanger sealing profile in the wellhead, is not significant to a Horizontal Tree. The same benefit with a conventional tree system requires expensive additional tubing hanger adapter or tubing spool equipment. • The tubing hanger-to-subsea tree interface is tested and verified at the time of landing the tubing hanger in the tree while the BOP stack is still in place. Should problems arise, this offers the possibility for recovering the tubing hanger and taking immediate remedial action without tripping the stack. A conventional tree-to-wellhead/tubing hanger interface cannot be verified until after the BOP stack has been recovered and the tree installed. A failure to interface properly can have serious time/cost implications, especially if the tubing hanger is damaged or not in the correct orientation when the tree lands. • Subsea tree single-piece spool body construction provides the maximum tree spool strength characteristics and reliability with minimum failure modes. These are considered to be stronger than conventional trees. • Successful subsea tree installation is not dependent on the full integrity of the wellhead internal sealing profiles. There are greater probabilities for successful installation on existing and perhaps old exploratory wellheads of uncertain integrity. The tree readily adapts to different wellheads from different vendors. • Horizontal trees are compact, have a low profile and an excellent strength-to-weight ratio. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Subsea component ‘building blocks’ can be arranged into many different tree layouts. This has given considerable flexibility to horizontal tree configuration and improved the opportunity of mass produced tree equipment by allowing the flexibility to manufacturers. Tree internals can be standardized while external characteristics can be varied or moved to suit the application. A Horizontal subsea tree design, using guidelines, can be readily converted to a guideline-less and funnel-down, wellhead re-entry system. This is achieved by adding a bolt-on funnel to the bottom of the tree. A funnel-down, BOP stack, wellhead reentry system can be used for guideline-less re-entry to a Horizontal Tree with little or no change to the standard guideline subsea tree. This will provide the lightest possible guideline-less subsea tree weight.

Figure 2.22 - Dual Bore Tree Stacked on Top of Tubing Adapter on Shop Floor



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2.3.2.5 DISADVANTAGES of Horizontal Trees • The tubing must be pulled first before retrieving the tree. Horizontal Tree recovery requires that the down-hole completion is recovered first, with the associated well killing operations through the BOP stack. Rationalization of this disadvantage is based on intervention data, that suggests that subsea tree failures, requiring the tree to be recovered, are a low percentage of all major failures requiring intervention. By far, the

Figure 2.23 - Dual Bore Split (Upper and Lower) Body Tree

• •

• •

greatest percentage of failures, relate to the failure of down-hole equipment, such as safety valves, gravel packs, etc. This suggests that intervention savings are actually likely to be accrued due to the use of Horizontal Tree technology, as down-hole workover frequency is much greater than the probability of tree recovery. A drill-and-complete scenario for Horizontal Trees currently requires two BOP trips. (Run the BOP stack; drill well; recover BOP stack; run tree; re-run BOP stack; finish complete; recover BOP stack). A Horizontal Tree does not include master and/or swab valves in the vertical bore of the tree to provide first-line barrier protection to the environment. It relies on a wireline plug to provide the first line barrier protection. Care must be taken to ensure that the critical wireline plug sealing surfaces in the tubing hanger and tree cap are not damaged during wireline operations. The subsea tree must be designed to withstand the loadings associated with a deepwater BOP stack and riser system. The bore of the subsea tree may be exposed to a very harsh drilling riser environment requiring special provisions for bore protection and bore cleaning in order to ensure successful tubing hanger installation and valve reliability.



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Tubing hanger installation requires the use of a sophisticated BOP subsea intervention tree and landing string system in order to provide for safe flow testing, wireline and coil tubing intervention and emergency disconnect scenarios. This adds complexity and time to the tubing hanger and down-hole completion, installation process. The Tubing hanger installation requires simultaneous control of the tubing hanger running tool, Subsea Intervention Tree and landing string system, BOP and subsea tree’s work-over functions. This involves up to four umbilicals and their control panels.

Figure 2.24 - Dual Bore Tree Being Deployed •

• • •

The tubing hanger hydraulic and electrical penetrations exit through the side of the subsea tree’s spool body. Control of hydraulic functions and monitoring of electrical functions is typically not provided although available, during installation of the tubing hanger system. The side outlet penetrations for control and electrical functions are additional leak paths in the primary tree bore during drilling and completion operations ROV’s must be used to connect/disconnect work-over controls between the BOP and Subsea Tree. A landing string leak or failure during well test or well clean up can divert hydrocarbons to the rig floor, burst the marine riser, or evacuate the marine riser allowing it to collapse under hydrostatic pressure.



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2.3.2.6 ADVANTAGES of Conventional Dual And Mono Bore Trees • Only one BOP trip is required in a drill-and-complete scenario. In addition, no temporary well abandonment plug is required between the BOP stack recovery and the tree installation as the tubing hanger serves that purpose. • The subsea tree can be recovered without having to recover the tubing hanger and down-hole completion because the tubing hanger lands in the wellhead and not in the subsea tree.

Figure 2.25 - Dual Bore Guidelineless Tree on Test Stand • •

The subsea tree is not required to withstand high loads associated with a Drilling BOP stack. Work-Over control connections are normally made between stab rings mounted on the tree mandrel and the LRP connector. No ROV is required.

2.3.2.7 DISADVANTAGES of Conventional Dual And Mono Bore Trees • The wellhead bore sets the tubing hanger outside diameter, leaving only a limited area for downhole access. This restricts the largest possible production bore size when including all the other down-hole penetrations required. Particularly the annulus bore that provides a circulation path that can also be sealed with a wireline plug. The 2” annulus bore is selected for the minimum reliable wireline plug size and exceeds the flow requirements. The available space is even more severely limited when considering a concentric tubing hanger design or for the need for annulus injection or gas lift capabilities. • If deepwater wells tend toward intelligent completions and/or simultaneous production from different reservoirs, conventional tree technology is inherently limited by the restricted space inside a wellhead. An alternative would be to use the hybrid tree, which lands a conventional tree on top of a horizontal tree, for these applications. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The subsea tree must be recovered in order to perform a tubing work-over. This disturbs the production flowline and umbilical connections. This creates new opportunities for damage to other hardware that is not easily recovered.

Figure 2.26 - Horizontal Tree With Trawl Protector Frame • •

• • •

•

A Monobore riser with a selector crossover mechanism at its base, in order to provide wireline access to the annulus can be unreliable. The subsea tree is typically installed on the dedicated work-over riser and wireline BOP intervention system in order to provide for flow testing, wireline and coil tubing operations, and emergency disconnect. This adds complexity and time to the installation process. This is the same as running the horizontal tree's tubing hanger on the subsea intervention tree and associated landing string system. The integrity of the wellhead interface is an issue. Damaged seal surfaces in the wellhead are not readily replaced and require an expensive tubing hanger adapter. No industry standard interface exists and the formalities of exchanging design information with a competitor and taking responsibility for its performance can be difficult. The tubing hanger’s orientation system is very complex with very significant orientation tolerances in the system. It relies on accurate setup and active interaction with the BOP stack. The interface between the tubing hanger and the subsea tree cannot be tested until the BOP stack has been recovered and the tree installed. A leak or failure of the riser system during well test or clean up will produce hydrocarbons to the environment. If the failure occurs near the surface safety issues arise.



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2.3.2.8 Other Types of Trees There are other specialized variations of subsea trees as well. These include TFL trees designed for use with special “through flowline” (TFL) workover equipment; “Single-Bore™” or “mono-bore” trees with a vertical production bore and a side valve for annulus access; “through-bore” trees with the tubing hanger in the tree body and “concentric” trees, used with a concentric tubing hanger and not requiring orientation between the tree and tubing hanger.

2.3.3

Components of a Typical Subsea Tree

The subsea Christmas tree is a complex engineered system of components. There are several different types of trees as explained below, and the tree configurations available even within a given type of tree (e.g. horizontal tree, or dual bore tree) vary widely from project to project. A subsea Christmas tree will typically consist of the following components: • • • • • •

• • • •

A tree connector to attach the tree to the subsea wellhead. The tree body, a heavy forging with production flow paths, designed for pressure containment. Annulus flow paths may also be included in the tree body. Tree valves for the production bore, the annulus, and ancillary functions. The tree valves may be integral with the tree body or bolted on. Valve actuators for remotely opening and closing the valves. Some valves may be manual and will include ROV interfaces for deep water. Control junction plates for umbilical control hook up. Control system. This includes the valve actuator command system and includes pressure and temperature transducers. The valve actuator command system can be simple tubing or a complex system including a computer and electrical solenoids depending on the application Choke (optional) for regulating the production flow rate. Tree piping for conducting production fluids, crossover between the production bore and the annulus, chemical injection, hydraulic controls, etc. Tree guide frame for supporting the tree piping and ancillary equipment and for providing guidance for installation and intervention. External tree cap for protecting the upper tree connector and the tree itself. Tree cap often incorporates dropped object protection or fishing trawl protection.



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Figure 2.27 - Typical Fail Closed Subsea Actuator (Valve Not Shown)

Figure 2.28 - Typical Valve Actuator With Rotary ROV Override Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Figure 2.29 - Horizontal Tree Tubing Hanger

2.3.4

Pressure and Structural Design Considerations of Subsea Trees

2.3.4.1 Pressure Design Pressure containing components of subsea trees are to be designed and tested in accordance with API 17D and API 6A for pressure ratings of 5000, 10000 and 15000 psi for most applications. The tree piping is normally designed in accordance with ASME B31.3. The guidelines in the API specifications are general and in many case open to interpretation. It is up to the manufacturer to apply his engineering judgement.



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The sources of pressure in a subsea tree include the following: • • • • • • • •

Production fluids. Hydraulic fluid. The hydraulic fluid pressure to the SCSSV may exceed the tree pressure rating. Effects of primary seal failures should be considered. Chemical injection fluids. Seal failures can result in migration of fluids Thermal expansion of fluids in closed cavities. Annulus pressure. It should be assumed that pressure will accumulate in the well annulus. External hydrostatic pressure. Test pressure. Seal verification pipeline Hydraulic lock. When mating parts are engaged, fluids may become trapped in the enclosed cavity and impede the engagement of the parts or cause damage to some component.

Seals The rules of the ASME pressure vessel code apply for the design of pressure containing shells. Seal design, however, is largely beyond the scope of the pressure vessel code, and a great variety of proprietary manufacturer’s designs exist. While the pressure design of the tree body, tree valves and piping is fairly straightforward, the interfaces between the various tree components require careful consideration or unexpected pressure effects may not be discovered until too late. It should be assumed that all seals are subject to failure, and at least one redundant or secondary seal shall be provided for every primary seal. The following are some of the seal interfaces to consider: • • • • • • • • •

Sealing between the production bore and the annulus bore. Tubing hanger to tree interface. Tubing hanger to wellhead interface. Tree connector to tree body interface. Valve blocks to tree body interface. Valve seats, stems, gates, and bonnets. Flowline and valve flanges. Running tool interfaces. Riser interfaces



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Figure 2.30 - Examples of Tree Cap Running Tools



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•

•


Seal Materials: Metal to metal seals. These employ a soft metal seal ring such as a stainless steel. The sealing seating surface is a harder material. Seal surfaces are usually overlaid with a non-corrosive material such as a high nickel alloy (Inconel). Metal seals come in a variety of forms including gaskets, rings, wedges and other geometric configurations. Elastomer energized metal seals. These are composite metal and elastomer seals designed such that, the elastomer allows applied pressure to energize the metal seals, or confined elastomer compression squeeze energizes the metal seal during the setting procedure. Even with degradation of the elastomer, the metal component maintains the seal. Some designs include provision for potentially the opposite to occur in which the elastomer provides a back up seal for metal seals that may be damaged during setting or through use – for example fretting if movement occurs with temperature or pressure cycling. Elastomer seals. The temperature rating and fluid compatibility of the elastomer is very important.

2.3.4.2 Quality Control and Testing Rigorous quality control and testing procedures are necessary to assure pressure integrity and correct fit and function of the components. Quality control, non destructive examination and testing requirements are laid out in detail in API specifications. There are four levels of quality assurance defined in API 6A, called Product Specification Levels. Product Specification Levels dictate the degree of inspection, testing and certification required for the primary pressure containing components. The following table summarizes PSL-2 to PSL-4. It should be kept in mind that API-6A was developed for surface wellhead equipment. PSL-1 is not usually considered applicable to subsea trees, and the applicability of the other Product Specification Levels is subject to interpretation. Subsea equipment will generally fall into the PSL-3 category and manufacturers often offer PSL-3 for only nominally higher cost than PSL-2 because they have standardized on materials and procedures that comply with PSL-3.

PSL Level PSL-2 PSL-2 PSL-2 PSL-3 PSL-3 PSL-3 PSL-4 PSL-4 PSL-4

API Product Specification Levels API Pressure Rating High H2S 5000 10,000 15,000 X X X X X X X X X X X X X

Close Proximity X X X X X

Manufacturers of equipment almost always try to adhere to API specifications, but the customer should specify requirements when purchasing. All factory acceptance testing procedures will be generated by the manufacturer and should be reviewed by the customer to ensure that specific field requirements will be met by the equipment. System integration testing is another process that verifies that the equipment is suitable for use. These procedures are normally very project specific and relate to various equipment interfaces within the project. Refer to the section on testing. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Most manufacturers maintain a quality assurance system within their manufacturing and testing facilities to monitor and identify problems as early as possible in order that rectifying actions can take place as early as possible to prevent schedule delay. The method that most companies employ is for a report, often call a non-conformance report or NCR, to be generated. This report is created so that experienced engineers and/or customer representatives can review and decide on what course of action to take to assist the project meet schedule and quality goals. These quality systems are normally in compliance with ISO 9000 series specifications or API Q1 specification. Manufacturing records of the material certificates, pressure tests and charts, nonconformance records, weld maps, nondestructive testing reports, x-rays, dimensional logs and other critical information such as test reports are collected, maintained, and published by the quality assurance group in the manufacturing companies. These records or parts of these records are required by regulation in many parts of the world in order to be able to deploy and use the subsea equipment.

2.3.4.3 Structural Design The tree connector, tree body, tree guide frame and tree piping must be designed to withstand internal and external structural loads imposed during installation and operation. The following are some tree and tree component load considerations: • • • • • • •

Riser and BOP loads. Flowline connection loads. Snagged tree frame, umbilicals or flowlines. Thermal stresses – trapped fluids, component expansion, pipeline growth. Lifting loads. Dropped objects. Pressure induced loads – external and internal.

Non-pressure containing structural components should be designed in accordance with AWS D1.1. Tree framework is usually designed around standard API post centres. This is typically, but not always true, even if the tree is designed to be guidelineless. API defines the position of four guideposts evenly spaced around the well centerline at a six foot radius. This equates to 101.82 inches between the posts on any side of the square corners that they form.

2.3.5

Subsea Tree Installation and Well Intervention Considerations

2.3.5.1 Running Sequence The following is a summary of the sequence of operations for installing a subsea tree onto a predrilled well: • • • • • •

Move the rig onto location. Launch ROV to locate the wellhead. Establish final position over wellhead with the aid of the ROV and drill string reference positioning system. If a guideline system is being deployed, re-establish guidelines. Retrieve the corrosion cap from the wellhead. Check the condition of wellhead sealing surface with the ROV and flush if necessary. Verify that a wellhead wear bushing is not in place. If it is, it will need to be retrieved. This is normally done through the BOP stack after it is run. For a horizontal tree, it



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•

•

• •


may be retrieved in open water to avoid having to trip the BOP stack for just the wear bushing retrieval. This exposes the wellhead gasket sealing area to potential risk of damage. Extra precautions may be taken to avoid this such as an extended rubber tipped bull nose being run below the retrieval tool, or other means or guidance such as a guide frame. Depending on the system design, a completion guide base or tubing hanger adapter spool may be deployed next. If not, the tree in a horizontal tree system will be deployed and then the BOP stack. Alternatively for a conventional system, the BOP stack will be run before the tree. Horizontal Tree – An elevation check tool may be optionally run to confirm the height of the last casing hanger in the wellhead with the same precautions mentioned above. The Horizontal Subsea Tree is then run on drill pipe with the tree running tool and land on the wellhead. The operation should be monitored by ROV. The umbilical should be strapped to the drill pipe as the tree is being run. The tree is then locked onto the wellhead and the gasket tested. The ROV then disconnects the work over umbilical junction plate and parks it above the tree running tool. The tree running tool and umbilical is then retrieved. The BOP and marine riser is then run and latched onto Subsea tree. The BOP can then be tested by running the isolation test tool which is then retrieved. Completion work is then carried out and the tubing hanger run after the bore protector has been retrieved. The tubing hanger is run with the landing string and usually subsea test tree – refer to the section on work over risers. The well typically flows through the landing string for well clean up and well test purposes. A crown plug is set in the tubing hanger after the well test or clean up is finished. An internal tree cap is then set and the BOP stack retrieved. A debris cap is then run onto the tree. Conventional Dual Bore Tree – The BOP stack is run onto the wellhead before any completion work commences. An elevation check tool may be optionally run to confirm the height of the last casing hanger in the wellhead through the BOP. Completion work is then carried out and the tubing hanger run after the bore protector has be retrieved. The tubing hanger is run and oriented with the installation and work over riser configured for the tubing hanger running tool – refer to the section on work over risers. Plugs are then set in the tubing hanger and the installation riser and BOP stack are retrieved. The tree is then run on the installation and work over riser configured for the tree running tool and lower marine riser package. The plugs in the tubing hanger are then retrieved and the well tested or cleaned up through the installation and work over riser. The riser is then retrieved and a debris cap run onto the tree. The guidelines are then cut or released usually by ROV. The rig then pulls anchors and departs.

All of the above operations must be carefully planned before mobilizing offshore in order to avoid costly errors. In addition to all the logistical issues to be addressed, a part of the preplanning should include consideration of weather limitations for the various operations and contingency plans for abandoning or suspending operations in case of bad weather.



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2.3.5.2 Tree Running Tools Subsea tree and other equipment deployment requires a suite of dedicated purpose designed running tools for the tree and tubing hanger. These are typically hydraulically actuated if they can not be weight or tension activated. In deeper water, torque gets difficult to transmit and control to the subsea equipment because of the flexibility in the pipe being used to transmit it. In addition the pipe can have a tendency to curl if torque resistance is offered by the subsea tool. It is difficult to count the number of turns that the subsea tool receives because the observed number of turns at the surface may be different to the number of turns at the seabed. Visual indication of the function of the tool can thereby be confusing or lost leading to problems and often damage if test pressures or over pulls are applied with a tool incorrectly functioned. Hydraulic tools can have hydraulic signals built into their design to confirm the correct function of the tool. Hydraulic signals can generally be assumed to reach the tool function if no pressure loss occurs which would otherwise indicate a leak. Hydraulic tools must be designed with a means of secondary override or fail safe to prevent problems in the event that the hydraulic system or umbilical fails while the tool is subsea. It would be undesirable to have a tool latched into a wellhead or tree with failed hydraulics so that it is stuck in place.

Figure 2.31 - Typical Tree Running Tool for Mechanical Connector (Hydraulics Are In the Tool)

2.3.5.3 Reentry Installation and workover systems are discussed in a separate section. It also describes various options for umbilical connection In either design the tubing may be reentered with the tree in place. The reentry mandrel profile is a profile that is provided on the top of the tree. It is designed to provide a mechanical connection and pressure containment for the mating connector on the “Installation and Workover” riser system, or the subsea BOP in the case of a horizontal tree. Recovery of the downhole tubing is another issue. With all conventional dual bore tree designs, the tree must be retrieved before pulling tubing. With horizontal trees, the tubing may be retrieved without pulling the tree. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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2.3.6


Subsea Tree Materials, Corrosion and Erosion Design

Considering the high cost for intervention, material selection becomes more critical for deepwater applications. Investment in the right materials will prevent or mitigate the likelihood of equipment failure due to the effects of corrosion.

2.3.6.1 Corrosive Agents Hydrogen Sulfide Hydrogen sulfide in even low concentrations can induce cracking in wrought materials, wherein nascent hydrogen ions produced by other corrosion activity at the metal surface do not recombine to gaseous hydrogen due to the action of sulfide ions. The H+ ions migrate through the metal recombining to H2 at discontinuities, creating very high pressures and causing the metal to crack. Another failure mechanism induced by hydrogen sulfide at higher levels is sulfide stress corrosion cracking. Sulfide stress corrosion failures tend to be catastrophic in nature because the effects are more pronounced on more highly stressed areas. The failures commonly occur in the heat-affected zone adjacent to welds. The measure of H2S concentration level is partial pressure. Low concentrations at high pressure are equivalent to higher concentrations at lower pressure. The effects are further influenced by temperature, but generalities do not apply well. For some materials the susceptibility to stress corrosion cracking decreases with increasing temperature. For others it may increase to a point and then decline. The presence of other corrosive agents such as chlorides may also have an effect on this behavior. Extensive testing of metal alloys by the National Association of Corrosion Engineers (NACE) has demonstrated that by controlling material hardness and microstructure the effects of stress corrosion can be mitigated. Guidelines are published in NACE MR - 01- 75. The European Federation of Corrosion, Oil and Gas Working Parties have also issued guidelines for H2S service for both plain steels and corrosion resistant alloys (CRAs). These present more detailed guidelines than the NACE document and are complementary to it. Carbon Dioxide Carbon dioxide in the presence of water forms carbonic acid which corrodes low alloy steels. The principle indicators to watch for are partial pressure and temperature, with corrosion rates increasing with the increase of either the temperature or the partial pressure. Above 60°C a protective deposit of iron carbonate is formed on the surface of low alloy steels that inhibits the corrosive effects of CO2. Any areas not so protected, due to a feature of operation that prevents the formation of this carbonate product or disrupts it, will continue to experience high corrosion rates. Much work in the field of CO2 corrosion has been conducted by DeWaard and Milliams [Simom-Thomas MJJ, DeWaard C, SmithLA: “Controlling Factors in the Rate of CO2 Corrosion.” UK Corrosion 1987]. Chloride Ions Chloride ions, present in the formation water of the reservoir, can cause cracking and pitting in certain materials. The cracking mechanism is chloride stress corrosion cracking, in stressed areas above 50°C. This corrosion mechanism is largely independent of pressure. Austenitic stainless steels, such as type 316, are susceptible. Low alloy steels and martensitic stainless steels (F6NM) are less susceptible to chloride induced stress corrosion cracking, but suffer from pitting corrosion.



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2.3.6.2 Erosion Erosion is a physical process, whereas corrosion is usually a chemical process. Apart from the direct loss of material from erosion effects, erosion often accelerates the rate of corrosion by preventing the formation of protective films or scale and exposing new metal to the corrosive environment. The worst erosion agent is sand in the produced fluids. It is impractical to design against high levels of sand production so sand control and monitoring is critical. There are several design features that can mitigate erosion effects. • • • • •

Large flow passages to reduce velocity. Long radius piping bends. “Cushion” tees. Overlay with harder and/or more corrosion resistant materials in susceptible areas. Extra material thickness in susceptible areas.

There is instrumentation available to monitor sand production and material loss. New technology is constantly under development. The first defense is prevention of sand production through careful design and deployment of well completions. If that fails the monitors may detect the problem before it becomes catastrophic. 2.3.6.3 Crevice Attack and Pitting Crevice attack and pitting are very common forms of corrosion in seawater. Pitting is caused by local concentration cells set up by differences in oxygen concentration, temperature, or fluid velocity. It is more prevalent under relatively stagnant conditions. Surface features or metallurgical factors, such as inclusions, breaks in the protective film, surface defects, etc. may help initiate pitting. Crevice corrosion occurs around gaskets, washers, fasteners, foreign matter, etc. that provide crevices that can become oxygen deprived. Crevice effects may be enhanced by simultaneous galvanic action. Elastomers containing sulfur or graphite are especially damaging to stainless steels. 2.3.6.4 Low Alloy Steels Where suitable, low alloy steels are desireable because they are inexpensive, easy to weld and readily available. The low alloy steels are carbon-manganese grades, in accordance with API or ASTM standards (e.g. AISI 4130 & 8630). Low alloy steels, however, are limited in their usefulness in corrosive service. For CO2 corrosion it is generally accepted that when the CO2 partial pressure is above 0.5 bar significant corrosion may occur in low alloy steels and their use is not recommended. Low alloy steels may be used in CO2 service if the wetted areas are clad with a protective overlay of corrosion resistant material such as Inconel or stainless steel. H2S induced stress corrosion cracking is a concern with low alloy steels where H2S partial pressure is above the allowable level. It can be mitigated, however, by controlling the material grain structure and hardness. 2.3.6.5 Martensitic Stainless Steels Martensitic grades of stainless steel (ASTM A182: F6NM, AISI 410) offer good resistance to both carbon dioxide and hydrogen sulfide. They have low resistance, however, to pitting corrosion due to chlorides, especially at higher temperatures. Extended exposure to high chloride environments may result in severe localized pitting, particularly where natural crevices exist. These steels are available in high strengths and are widely used in down hole and wellhead applications. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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2.3.6.6 Austenitic Stainless Steels Austenitic stainless steels (e.g. AISI 316 L) have excellent corrosion resistance up to 50 bar partial pressure of CO2. However, chloride stress corrosion resistance is limited to operating temperatures up to 50°C. They can be susceptible to crevice corrosion. Austenitic stainless steel is immune to sulfide stress corrosion cracking up to 0.5 bar partial pressure of H2S at temperatures up to 60°C. The low yield strength of austenitic stainless steels renders them unsuitable for structural components but they are extensively used for fittings and connectors. They are particularly suited for gasket materials where their low yield ensures that they deform preferentially to the ring groove and deform readily into any surface irregularities.

2.3.6.7 Duplex Stainless Steels Duplex stainless steels are high alloy steels comprised of both austenitic and ferritic phases. The two most commonly specified grades of duplex stainless steels are UNS 31803 (with 22% Cr and 5% Ni), and UNS 32750 (25% Cr, 7% Ni). The 25%CR material is sometimes referred to as “super duplex” or high performance duplex. Duplex stainless steels offer better resistance to CO2 and chlorides than the austenitic (316L) stainless steels and have higher mechanical strength. Duplex stainless steels are frequently used for piping and downhole tubing. It is not used for large forgings because of the expense and because of reduced mechanical strength near the center of thick forged sections.

2.3.6.8 High Nickel Alloys The high nickel alloys containing 25% to 65% Ni are the most resistant to both CO2 and H2S corrosion. No limits are given for CO2 corrosion, whereas H2S corrosion is a function of the nickel content. Inconel alloys UNS N08825 and UNS N06625 are the most widely used high nickel alloys in the oil industry. They are usually more expensive than the duplex stainless steel alloys. High nickel alloys are used in both solid forgings and as weld cladding on less expensive low alloy steel substrate. Overlaying the exposed surface with a high nickel alloy can mitigate crevice corrosion effects. This is the case with ring gasket seal areas. It is important that the alloys used for the overlay have hardness greater than the gasket seal material to minimize the risk of locally yielding the ring groove.

2.3.6.9 Coatings and Cathodic Protection It is normal to use sacrificial aluminum anodes to protect the steel components of subsea trees, templates, manifolds and pipelines from seawater corrosion. The anodes are usually used in conjunction with a high quality epoxy coating system applied to the low alloy steel components. Stainless steel components are typically left bare. The anodes afford the Austenitic stainless steels some protection against pitting and crevice corrosion as well. The coating helps to minimize the rate of consumption of the anodes, allowing for fewer anodes and extending their life. The anodes must be designed for the life of the equipment and must allow for degradation of the coating. Replacement of anodes is not an option, or a very expensive one. The coating system commonly consists of an epoxy primer applied over a surface that has been prepared by cleaning and grit blasting to “white metal”, followed by the application of two coats of high build polyamide epoxy.



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2.3.7


Tree Mounted Controls and Instrumentation

Tree mounted controls are dependent on operational, functional, and interface to the subsea system requirements. Typical tree mounted equipment includes the Subsea Control Module (SCM or pod) with mounting base and funnel, pressure and temperature sensors, choke position indicator, sand detectors, erosion detectors, downhole gauge interface, junction plates, and parking positions for both hydraulic and electrical jumpers. The SCM is responsible for gathering all instrumentation data on the tree, including sensor readings from all tree mounted gauges as well as downhole gauge readings and sending that information to the topside control system for action and interpretation. The SCM also filters the hydraulic fluid supply and then, when directed, to actuate an appropriate solenoid valve to actuate a valve on the tree. The SCM can also record the “signature” of the valve by monitoring the outlet pressure on that line. The signature is compared automatically on the surface to the normal signature of the actuator to verify its function and proper position. Junction plates are mounted on the tree to provide an interface point for the hydraulic, chemical and/or electrical jumpers or umbilical to mate to the tree to supply hydraulic signals, hydraulic power, chemicals for injection, electric power, or electronic control signals the tree. The jumper plates are also connected during installation and workover functions to allow the rig local control of the tree during these operations. There are a variety of gauges that can be placed on the tree, separate pressure and temperature sensors (or combined) can be placed in the annulus and the production bore and upstream and downstream of the choke. The sand detector can be either intrusive or acoustic and be set to warn the operator incase of sudden or progressively increasing sand production. Parking positions are included on the tree to allow parking of chemical/hydraulic jumpers, and electrical jumpers during workover, pulling of the tree or retrieval of the SCM. The control system is described in detail in Section 4.1.

2.3.8

Flow Assurance Considerations

Flow assurance has become something of a catch phrase in the subsea industry, but for good reason. As developments move into deeper water lower seabed temperatures are encountered, increasing the likelihood of flow problems, the means of intervention are fewer, and the costs are higher. While most flow assurance issues are with the flowlines, the mitigation of flow assurance problems may begin at the subsea tree, or even downhole. The following are some possible sources of, or contributors to flow assurance problems. •

• • • •

•

Hydrate formation. Joule-Thompson effect, low ambient seabed temperatures and longer exposed risers contribute to the likelihood of hydrate formation in deepwater developments. Wet gas at high pressures can form hydrates at temperatures well above those encountered on the seabed. Wax deposition. If the seabed temperature is below the wax crystallization temperature (cloud point) deposition of wax on the walls of the flowlines may take place. High viscosity, high pour point. Low temperature result in higher viscosity and diminished flow rates. Asphaltenes. These can precipitate similarly to wax crystals and restrict the flow. Sand production. Sand can accumulate in flowlines and restrict flow. If any of the other contributors to flow assurance problems are present the problems can be greatly compounded with the additional presence of sand. Sand production can very seriously and very rapidly degrade the pressure integrity of subsea systems. Scale formation. Scale deposits can restrict flow passages.



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There are a number of measures that can be taken to mitigate flow assurance problems. Among them are the following: • •

•

•

2.3.9

Insulation: The subsea tree and flowline may be insulated against the cold seawater. There are many types of insulation. Syntactic foam is often used for deep water applications because of its high compression strength. Chemical injection: Wax inhibitor, pour point suppressant, methanol, and scale inhibitors may be injected at the subsea tree, or even downhole. The chemicals are often delivered through tubes in the production control umbilical reserved for that purpose, or through a dedicated umbilical or tube bundle. Actuated injection valves and check valves are typically provided at the injection point on the subsea tree. Downhole injection requires that the tree and tubing hanger be ported, and a downhole injection line installed with the completion tubing string. Heating: While not commonly implemented due to cost and technical obstacles, heat tracing of the subsea tree and flowline, accompanied by insulation, could be a solution to an extreme flow assurance problem. An alternative may be to circulate hot water within a production bundle, or stabilised crude oil where two flowlines are connected to the production manifold. Pigging: Regular pigging can control the accumulation of wax, sand and asphaltenes. Pigging issues are discussed in more detail elsewhere.

Deep Water Design Considerations

Deep is a subjective term, but as developments move into ever deeper water those issues that have always posed challenges to subsea engineers become even greater, and the solutions that worked successfully before no longer suffice. It is the designer’s challenge to identify where to apply new solutions while building on what has worked in the past. The following are some deep water design challenges:

2.3.9.1 High Hydrostatic Pressures High hydrostatic pressures can sometimes have unexpected effects on equipment. following are some things to consider. • • • • • •

The

If pressures are not balanced, the hydrostatic pressure can force parts together or apart with unexpectedly high force, causing seizure or failure. Hydrostatic pressures can collapse elastomeric seals, hoses and other soft components. Spring return actuators may be affected, causing valves to open or close unexpectedly. Umbilical coupler seals may allow seawater intrusion, or junction plates may become impossible to disengage. High pressure could be trapped inside equipment that has been exposed to great depth and could present a hazard to personnel on the surface when the equipment is retrieved. Hydrostatic differentials due to differing specific gravities of different fluids can cause inadvertent reactions. These can include “U-tubing” of fluids into umbilical hoses or hydraulic function of a running tool or device where the control fluid or chemical in the umbilical hose is a lighter fluid than the ambient sea pressure or completion brine in the marine drilling riser and well.



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2.3.9.2 Equipment Guidance The long vertical offset complicates the station keeping for the drilling rig and makes the use of guidelines impractical. The following are some considerations. • • •

Guide funnels to capture devices and guide them into position. Fenders and guard rails to protect other equipment from damage. Soft landing connectors. These allow rough engagement and capture of a component (e.g. a flowline connector) without risk of damaging seals, and then a hydraulic mechanism controls the movement from there to the final position. Rough engagement can be difficult to avoid if the deployment vessel is subject to wave motion.

2.3.9.3 Low Temperatures. Extreme low temperatures can result from gas expansion (e.g. across a choke) combined with the low ambient seabed temperatures. Besides the flow assurance issues addressed above, low temperatures may have other effects. • • •

Increased stiffness of elastomers. Elastomer material selections may have to be reviewed, or metal seals employed. Thermal stresses due to high temperature differential or temperature changes. Clearances may be affected. Flexibility of piping loops may have to be addressed. Material embrittlement. Low temperature material may have to be specified and Charpy notch toughness testing conducted.

2.3.9.4 Diverless Installation All completion operations must be conducted without the benefit of diver intervention. Diverless tree technology is well developed and ROV intervention tooling is pretty well adapted to supporting subsea completions. The area that is most challenging in this regard is subsea flowline tie-ins.

2.3.9.5 Long Trip Times Tree installation requires numerous round trips to run and retrieve the various tree components and running tools, as detailed in Section 2.3.5. The time required for each operation increases with the water depth. In addition, the day rate cost is usually higher for deep water drilling rigs. Finally, the risk of a mishap with each trip increases with increased water depth, due to longer exposure times and less precise positioning control. The designer may address this by finding ways to minimize the number of trips required. The operator may address it by carefully planning all completion procedures.



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2.3.9.6 Riser Considerations Drilling risers and installation and completion risers are both affected by deep water considerations. Riser loads can increase with depth due to current loading and increased weight of the riser due to increased length. This requires increased connector capacities There is increased risk of riser leakage because of the longer lengths of riser in deep water. This can be hazardous during well flowing operations to a rig above the well. High pressure gas or hydrocarbons released at depth expand tremendously in volume as they rise to the surface. Thus a small volume of high pressure gas at depth can be a large gas bubble or cloud at the surface. This of course represents tremendous safety risk. Riser disconnect becomes more difficult at depth because of hydraulic response time and because it can take much longer to bleed down contained riser pressure. Installation and work over riser systems for deep water will typically include a number of valves that will enable the riser to be closed and then disconnected while under pressure. Deepwater riser systems are now being deployed with quick response electro-hydraulic muliti-plexed control systems to enable rapid emergency disconnects if required. Rig BOP and riser deck storage areas must be larger on deeper water rigs, or the riser must be offloaded to support vessels.

2.3.10 Factory Acceptance, Performance Verification, and System Integration Testing 2.3.10.1 Factory Acceptance Testing Factory Acceptance Testing, commonly referred to as FAT, is always performed on newly manufactured subsea equipment to ensure that the individual components and items of equipment meet the specified requirements and function correctly. After successful final assembly and FAT, equipment is then almost always further verified by Systems Integration Testing (SIT). SIT is described further in this document. In addition to FAT and SIT, subsea equipment is subjected to qualification testing, frequently referred to as Performance Verification Testing (PVT), if the equipment is new design or significantly changed from proven equipment. Various procedures for this type of testing are laid out in, or adapted from, PR1 or PR2 testing standards defined in API specifications for equipment. PVT is described further in this document. All testing is normally heavily based on relevant ISO and API Standards. In order to try to ensure successful FAT and thereby assist with maintaining project schedules, subsea equipment is manufactured and tested in accordance with predefined quality procedures and quality plans. These procedures and plans are prepared before manufacture commences and define the levels and methods of inspection and testing that will be followed during the manufacturing process. A proficient quality system and well defined quality plan will identify defects and problems early in all stages of manufacture so that corrective actions can be invoked to ensure timely delivery of good equipment. This normally involves a substantial amount of planning, experience and skilled manpower to enhance the project execution. If not done properly, a cumbersome and burdensome quality system can hinder rather than enhance it. Body pressure tests must be performed before other pressure tests. The remaining tests can be sequenced and combined to suit manufacturing consideration, provided that all tests are performed. Body tests are intended to reveal any structural flaws in components as early as it is safe to do so. Having passed this overload test, a level of confidence is established for the safe conduct of future tests carried out at the lower maximum working pressure. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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During manufacture, components should be dimensionally controlled to verify conformance with design drawings. Acceptable deviations will occur and should be recorded. An experienced engineer typically approves these after the quality assurance process identifies them. All components, including spares, should be tested. Jigs and dummies may be used where testing of actual interface components is not practical. It is, however, recommended that the actual equipment be used where feasible. For large orders with identical equipment items, testing should as a minimum be carried out on the initially produced equipment. Fit tests should be performed in such a way as to prove the guidance and orientation features of the components. Misalignment checks should consider stack-up tolerance, stack-up elevation, horizontal plane, orientation, and angular alignment. Equipment with self-alignment features should intentionally be misaligned to verify its alignment capability. Functional checks should include make-up, normal emergency release, reversibility, repeatability, and pressure integrity. The sequence and items to be tested would normally be individual components, running tools, subsystems, and the total system assembly. After successful FAT and SIT, the equipment should be suitably preserved and packed as required prior to delivery. 2.3.10.2 Performance Verification Testing Performance verification testing or qualification testing is done to defined procedures to qualify new or significantly modified product designs. Key parameters requiring consideration are the simulation of all loads, pressures, and operating conditions that the system will be subjected to during all phases of installation and operation. Equipment or fixtures used to qualify designs using performance verification procedures should be representative of production models in terms of design, dimensions, and materials. If a product design undergoes any changes in fit, form, function or material, the manufacturer should document the impact of such changes on the performance of the product. A design that undergoes a substantive change becomes a new design requiring re-testing. A substantive change is a change identified by the manufacturer, which affects the performance of the product in the intended service condition. This may include changes in fit, form, function or material. Typical examples of this are size or pressure rating changes. A change in material may not require re-testing if the suitability of the new material can be substantiated by other means. Hydrostatic pressure tests are acceptable for all equipment performance verification pressure tests to API 17D. End users often require and manufacturers may at their option substitute or add gas test for some or all of the required performance verification pressure tests. Hydrostatic and gas performance verification test procedures and acceptance criteria should meet the requirements set by the API specifications or better. Gas testing is generally specified for equipment that will be used for gas service. API Specification 17D and 6A lists the equipment that must be subjected to repetitive hydrostatic pressure cycling tests to simulate startup and shut down pressure cycling which will occur in long-term field service. For these hydrostatic cycling tests, the equipment will be alternately pressurized to the full rated working pressure and then depressurized until the specified number of pressure cycles have been completed. No pressure holding period is required for each presssure cycle during the cycling phase of testing. A standard hydrostatic (or gas if applicable) test will be performed before and after the hydrostatic pressure cycling test. The cycling tests are additionally subjected to controlled alternating heating and cooling. Repetitive temperature cycling tests simulate startup and shutdown temperature cycling which will occur in long-term field service. For temperature cycling tests, the equipment will be alternately heated and cooled to the upper and lower temperature extremes of its rated Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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operating temperature. During temperature cycling, rated working pressure will be applied to the equipment at the temperature extremes with no leaks. Temperature cycling from room temperature to the lower temperature extreme plus cycling from room temperature to the upper temperature extreme may be substituted for temperature cycling directly between the two temperature extremes. Performance verification tests at rated working pressure or greater are performed at test temperature equal to or less than the minimum rated operating temperature classification, and at a test temperature equal to or greater than the maximum rated operating temperature classification to confirm the performance of the equipment. As an alternative to testing, the manufacturer can provide other objective evidence, consistent with documented industry practice, that the equipment will meet performance requirements at both temperature extremes. Not all types of components are identified in the mentioned API specifications and therefore interpretation of type of function is often used to define testing requirements for components. Typical examples of these components include many horizontal tree components such as internal tree caps and crown plugs. Performance verification testing, Finite Element Analysis (FEA) or classical engineering analysis can be used to verify the manufacturers rated load capacities for API Specification 17D equipment. If testing is used to verify the design, the equipment should be loaded to the rated capacity at least three times during the test without deformation to the extent that any other performance requirement is not met. If FEA or engineering analysis is used, the analysis will be conducted using techniques and programs that comply with documented industry practice. Life cycle/endurance testing, such as make-break tests on connectors and operational testing of valves, chokes, and actuators, is intended to evaluate long-term wear characteristics of the equipment tested. Such tests may be conducted at any temperature. API Specifications 6A and 17D list equipment that should be subjected to extended life cycle/endurance testing to simulate long-term field service. For these life cycle/endurance tests, the equipment will be subjected to operational cycles per manufacturer’s performance specifications (i.e., make up to full torque, break out, open/close under full rated working pressure). Scaling may be used to verify the members of a product family. A product family is a group of products for which the design principles, physical configuration, and functional operation are the same, but which may be of differing size. The design stress levels in relation to material mechanical properties must be based on the same criteria for all members of the product family in order to verify designs via scaling. Testing of one size of a product family will verify products one nominal size larger and one nominal size smaller than the tested size. Testing of multiple product sizes also verifies two nominal sizes larger than the smallest item tested and two nominal sizes smaller than the largest item tested. The test product(s) may be used to qualify products of the same family having equal or lower pressure ratings. The procedures used and the results of all performance verification tests used to qualify equipment to API Specifications must be documented. The documentation requirements for performance verification testing are laid out in the API specifications. When the design is proven and the prototype has passed PVT testing then manufacture of the components to be delivered can begin.

2.3.10.3 System Integration Testing System Integration Testing (SIT) is performed to verify that equipment from various suppliers, which must interface with each other, fits and works together acceptably. Additionally, it can be an excellent opportunity for training of personnel including familiarization with equipment and procedures. This is an important factor during all integration test activities. This aspect is particularly influential in promoting competence, safety and efficiency during installation and operation activities. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Reliable rig handling systems and trained personnel are of vital importance to the overall success of a subsea project during the subsea installation, well completion and production testing phases. SIT is an opportunity for the tests to contribute to the success by optimizing installation procedures and familiarizing offshore personnel with equipment and equipment handling to promote efficiency and safety in installation and operation of subsea production wells.

The SIT can be used to expose relevant equipment to abnormal situations which can occur during operation such as low hydraulic supply pressure, low voltage supply etc. The purpose is to reveal “system margins”. Depending on the production system, there are many types of checks that should be performed. If possible, it is best to perform the test utilizing the actual subsea equipment and tools. If the possibility to perform full-scale testing does not exist, system performance should be demonstrated by verification analysis. Tests should include simulations of field conditions for all phases or operations from installation through maintenance. Special tests may be needed for handling and transport, dynamic loading, and backup systems. The SIT may be appropriate to verify data on response time measurements, operating pressures, fluid volumes, fault finding, and operation of shutdown systems. The different tests performed during integration testing should be used to check reliability, and should be used to demonstrate tolerance requirements and the correct functioning of the complete system. Detailed procedures for the integration tests should be prepared prior to starting the tests.

Figure 2.32 - A Typical Workover System SIT With The Subsea Tree Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The subsea system should be subjected to the following activities during system integration testing: • • • • • • • • • • • • •

Check the cleanliness of the hydraulic control fluid and circuits. Test of all mechanical and hydraulic functions. Test of tree system using temporary IWOC system. Documented integrated function test of components and sub-systems. Final documented function test of all electrical and hydraulic control interfaces. Documented orientation and guidance fit tests of all interfacing components and modules. Simulation of installation, intervention and production mode operations as practical in order to verify and optimize relevant procedures and specifications. Simulation of ROV intervention operations using a mock-up. Include ROV pilot training during SIT. Operation under specified conditions including extreme tolerance conditions as practical in order to reveal any deficiencies in system, tools and procedures. Operation under relevant conditions as practical to obtain system data such as response times for shut-down actions etc. This could include shallow water tests and rehearsals. Subject to testing to demonstrate that equipment can be assembled as planned and satisfactorily perform its functions as an integrated system. Fill with correct fluids, lubricate, clean, preserve and pack as specified. Subject to a final inspection in order to verify correctness of the as-built documentation.

It is important to functionally test all manual override functions in connection with the above tests. The purpose of the intervention test is to verify the interfaces and the functions of the ROV systems and tooling. In addition, hatch operation, guidepost/mini-post replacement and mechanical override of connectors (if not performed at FAT), as well as tests using any Company provided items should be performed to verify interfaces and functions. All additional tooling interfaces such as choke insert and POD running and retrieval tools should be integrated with the final subsea equipment assemblies. If dummy structures are to be utilized during testing, a verification of the possible dummy structures should be performed to verify that the dummy structures are in compliance with the real structures. The facilities on the integration test site should include test facilities with crane capacity for handling and stack-up of x-mas trees and associated equipment. The test facility should be clean and not disturbed by other activities. The test facility should be suitable for performing flushing operations. Any activity generating particles including grinding etc. must not take place in this facility. The test facility should be suitable for performing system tests of the production control system involving sensitive computer equipment and include adequate indoor facilities for storing of equipment and site office facilities for the client. A typical format for a subsea equipment integration testing procedure could include the following: Purpose/Objective, scope, requirements for fixtures/set-ups, facilities, equipment, personnel responsibilities, performance data, changes, acceptance criteria, and certification and reference information. Outline commissioning procedures should be developed prior to establishment of the test procedures. Hence the end user requirements should be defined prior to developing the actual test procedures. The idea behind this requirement is to maximize applicable experience from one phase to the next. Hence experience gained during FAT is applicable for test activities during SIT and commissioning. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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A schedule for the activities should be developed prior to the start of the integration test. Equipment logistics should be part of the schedule. The Operation and Maintenance Manuals (O&M’s) should be used as guidelines for establishing the test procedures. Test procedures should be signed off step by step during each test operation. A daily log should be written for each test activity. Test findings should be briefly described in the log. A query system that should handle all test findings should be developed including procedures to rectify the findings. The manufacturer should arrange frequent status meetings with operator during the integration test phase. The operator’s personnel should have access to all test facilities during testing. They may monitor or witness all tests and should have free access to the test results. Emphasis should be put on the requirement that the operator’s offshore-nominated personnel have access for complete insight into system functions, system operation and debugging methodology. Photographic records can be of considerable value in future diagnostic work when the equipment is subsea. Comprehensive still photography and video records are recommended. The test program should include an index of the test procedures, equipment-handling procedures and further identify facilities, equipment, materials and other items required for the program. The manufacturer should develop and establish procedures and check lists necessary in order to verify that the requirements of the contract are met. The integration test procedures should be developed in such a manner that operational conditions can be simulated. All procedures for system integration tests should be reviewed and approved by the operator prior to start of the test. The test procedures should include defined acceptance criteria.

2.3.11 Manufacturers Capabilities There are five main subsea tree equipment manufacturers in the world. These are • • • • •

ABB Vetco Gray Cameron Dril-Quip FMC Kvaerner

Although the amount of equipment each have delivered over the years differs, they have similar capabilities with varying levels of manufacturing, sale,s and service support around the world. Other companies who offer larger subsea packages such as manifolds and fabricated equipment primarily use equipment supplied by the companies mentioned above. Several other companies exist that manufacture subsea valves, subsea connection systems, subsea BOP stacks, etc. exist but are not considered to be subsea production equipment supply specialists because their range of products are limited.



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3


SUBSEA PRODUCTION MANIFOLDS AND TEMPLATES

3.1

Overview of Functions of Subsea Production Manifolds & Templates

While subsea production manifolds and subsea templates have distinctly different functions, very often the functions of the two are combined into one unit (a subsea template), leading to confusion in the terminology. While a subsea production manifold is never a subsea template, a subsea template can be, and often is, also a subsea production manifold.

Subsea Tree

ROV Panel

Choke Module

Control Pod Module

Umbilicals

Flow Line (2 off) Well Mud Mat

Spool Jumper Flow Line Connector Jumper Connector

Manifold

Connection Hub Flying Pigging Valve Leads

Figure 3.1 - Diagram Showing a Typical Subsea Manifold and Subsea Field Equipment Arrangement



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3.1.1


Subsea Production Manifolds

The general function of a subsea manifold is to gather and distribute production through an arrangement of piping and valves. Some specific functions are: •

To collect the flow from individual satellite wells into a production header and control the delivery of the commingled flow to a field production gathering flowline. Typical Connection Hubs

Retrievable Pig Loop

Conductor Support

Figure 3.2 - Example of a 4- Well Subsea Manifold With Flowline Connections •

To collect the flow from several field production gathering flowlines and deliver that flow to a larger production export pipeline. To isolate the production from individual wells and deliver it to a well test header or a well test flowline.

•

Figure 3.3 - Deepwater Subsea Manifold With Multiple Flowline Connections • •

To segregate high pressure and low pressure production into separate high pressure and low pressure headers and flowlines. To control the flow from individual wells by means of subsea chokes. Wells may be choked at the trees or at the manifold.



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• • • • •

3.1.2


To distribute injection water or gas from a common supply header to individual injection wells (water injection or gas injection manifolds). To distribute lift gas from a common lift gas header to individual wells (lift gas manifold). To facilitate pigging of subsea pipelines by provision of pig isolation valves, tees and pig detector instrumentation mounted on the manifold structure. To provide structural support of the piping and flowline connector at the flowline connection interface. To provide ROV or installation tool interfaces for installation of flowlines, chokes, pig launchers, pig receivers and other components.

Subsea Templates

The primary function of a subsea template is to provide guidance for positioning wells and controlling their positions relative to one another. In addition, a subsea template may

Figure 3.4 - Nine Slot Template Being Lifted from a Work Boat (Left) and being Deployed from a Jack-Up Drilling Rig (Right)

incorporate many of the functions of a subsea manifold described above, all in one integral assembly. Some specific functions of a subsea template are: • • • • • •

To provide a guide for positioning the well conductor and guiding the conductor during installation. To control spacing between adjacent well conductors. To provide guidance and support for the BOP in some cases. To provide guidance and support for well completion equipment (e.g. trees) in some cases. To accommodate pre-installation of well flowline piping and facilitate interface of the production trees with their flowlines. To accommodate pre-installation of tree control hardware and facilitate interface of the production trees with their controls.



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3.2


Features of Typical Subsea Production Manifold or Template

The following is a summary of the main features of subsea production manifolds and templates. Since the functions of subsea production manifolds and templates overlap, some components may be applicable to either or both, depending on the configuration. •

A structural weldment or frame for supporting the conductor guides and/or manifold equipment and sustaining structural loads of transportation, installation, workover and/or operations. Construction may be I-sections or tubular members. In general Isections are more efficient structurally. Tubular construction can provide some buoyancy, which can be an advantage for installation, but must be designed for hydrostatic pressure and is typically more expensive.

Figure 3.5 - An Example of a Twelve Slot Well Supported Drilling Template. Note Removable Pile Guide Sleeve Attachments in Foreground. •

• •

• • •

A mud skirt is often provided. It is designed to penetrate into the soft bottom and provides lateral shear resistance. If the soil shear strength is high enough this may be adequate for supporting the structure. If the soil is very soft, piles may be required. Suction piles may be used in soft clay bottoms. Soft soils with sand and aggregate may require driven piles. Harder bottoms may require drilled and cemented piles. Templates will have guide sleeves for positioning well conductors. They should be long enough to keep the conductor in a nearly vertical position during installation. Spacing varies depending upon the requirements. A cover may be provided for dropped object protection. In shallower waters sometimes the structure is designed for over-trawling by fishing trawls without snagging. Templates may have hinged or removable roof hatches over each well to provide access to a well or subsea tree. These may be designed for opening or removing with a line or tool from the rig above, using ROV assistance if necessary. Production flowline connections can be installed on the template, positioned so as to mate up with a receptacle on the tree when it is landed. These may be hydraulically actuated by means of the IWOC system. Flowline branch valves and flowline chokes. These provide control of individual wells. Header piping and header valves.



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•


It may be desirable to mark manifold piping for identification, for example with flowline numbers or flow direction arrows. Flowline Jumper Tie In Hubs

Typical Fold Down Well Slot Porches

Figure 3.6 - Five Slot Template and Manifold With Hinged Well Slots



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3.3 3.3.1


Design Considerations Number of Wells

The number of wells served by a template will determine its size. Templates may be designed for two wells to two dozen or more. Template size is often limited so as to fit through the moonpool of a drilling rig. Larger templates (accommodating more wells) are sometimes hinged so they can be folded up for passage through the moonpool and then unfolded for deployment on the seafloor. Another method of accommodating more wells and installation through the moonpool is with a modular template. These designs consist of individual interlocking sections or modules, each serving one to several wells, that are deployed individually and connected to one another on the seabed, usually by some sort of guide pin and sleeve arrangement. They are often used when the ultimate number of wells is unknown, as a way of keeping the initial capital cost of the development as low as possible. Very large integrated templates may be too large for installation through the moonpool. In such cases a heavy lift vessel may be used to deploy the template. As a rule, the more equipment that can be pre-installed on the template the better. This minimizes the time required for the rig or installation vessel to deploy the template.

Figure 3.7 - Large Multi-Well Template and Manifold Being Transported by Barge for Installation by Lift

3.3.2

Production Piping

Production manifolds are usually pre-assembled complete with most of the piping, valves and controls installed prior to deployment. For large template structures that include a production manifold, the production manifold may be installed as a module or several modules subsequent to the template deployment. This is necessary in the case of modularized templates run through the moonpool of a drilling rig. The piping itself is designed to the same standards as the piping on subsea trees, typically the ASME B31.3 piping code or some equivalent. Flowline branch and header sizing is normally done in accordance with API 14E.



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Piping materials are typically carbon steel, low alloy steel or high alloy steel depending on the service. The design pressure of the manifold must be carefully considered. The simplest approach is to match the shut-in pressure of the wells. If this is impractical due to cost, then there needs to be careful consideration to overpressure protection, by assuring proper valve shut-in sequences, valve failure positions and pressure relief at the host production facility (topsides).

3.3.3

Bottom Conditions

Bottom conditions will affect the design of the subsea production manifold or subsea template. The following are some issues relating to bottom conditions that must be considered: •

•

Soil shear strength. This is a measure of the softness or firmness of the bottom. It will indicate the ability of the seabed to support the load of the template or manifold. The size of the supporting mat or the depth of the mud skirts will be dictated by the load bearing capacity of the soil. Sometimes the soil may be too soft to adequately support the weight of the template or manifold by means of a mat. In such cases pin piles or suction piles may be used to support the structure. In the case of templates, the well conductors may provide the support.

Connector Profile

Template Landing and Lockdown Profile

Conductor

Figure 3.8 - Typical Mudline Support Equipment on First Well Casing for Well Supported Drilling Template • •

Soil borings must be done to assess the geotechnical characteristics of the soil for the piles, mud mat or skirt design. Bottom slope. The sea floor should preferably be near level. Leveling devices may be required for leveling the template or manifold structure after it is landed on the seabed.



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• • •

3.3.4


Bottom stability. Areas prone to mudslides or erosion should be avoided. Outcroppings or debris. These will interfere with the leveling of the structure and should be avoided or removed. A sea bottom hazard survey is recommended prior to deployment of the template or manifold. Poor visibility. Debris stirred up by currents or the propeller wash of the ROV may interfere with visibility if the bottom is very silty. Avoid ROV interfaces too close to the seabed.

Installation Method

Templates are commonly installed by a drilling rig as the first step prior to drilling. The template is often installed from a floating rig through the moon pool or from jack-up in shallower water. They are run on retrievable equipment usually using drill pipe or collar from a rig.

Figure 3.9 - Four Well Manifold Being Deployed From a Barge

Standard guideline or guidelineless techniques can be deployed on the individual well slots. If the template is too large to be handled through the moonpool, it may be keelhauled, that is passed from another vessel alongside and swung under the keel of the drilling rig, where the load can be transferred to the rig and lowered on drill pipe by the rig to the seabed. This transfer operation is potentially risky and very weather sensitive. Very large templates are sometimes installed using a lift barge. This poses problems in deeper water, for mooring the barge, providing enough wire rope capacity to reach the seabed and maneuvering the template or manifold into place. For very deep water a dynamically positioned heavy lift vessel would be required. This option of course causes the project to incur lift barge mobilization and demobilization and lift costs.



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3.3.5


Tie-In Requirements

Subsea trees and manifolds require tie-in of flowlines and control umbilicals once they are deployed. In deep water these must be done diverless, except for the use of atmospheric diving suits (ADS) up to depths of about 750 meters. ROVs are very effective for managing control umbilical stab connections, for manipulating valves and operating hydraulic tools. Flowline tie-ins are one of the more technically challenging operations in a deepwater development because the loads typically exceed the capabilities of most ROVs. Design considerations for tie-ins to subsea production manifolds and templates include the following: • • •

The size of the pipeline tie-in. The larger the line the more difficult it is to handle. The number of tie-ins required. Adequate spacing must be provided for ROV and tool access during installation. Provisions for future tie-ins may be considered. The type of connector to be used. Different types of connectors require different intervention tooling for installation, and the space requirements may be different.

Flowline Connection Hub

Well Connection Hub

Deployment Yoke

Mudmat

Figure 3.10 - A Typical Deepwater Pipeline End Manifold (PLEM) •

•

The installation method. Installation methods include ADS diver assisted, ROV pull-in or “stab and hinge-over”. The installation method determines the connector orientation for example, or the type of connector to be used, or the loads likely to be imposed during installation. Guidance methods. Guideline or guidelineless techniques may be used. For guideline methods, ROV retrievable guideposts may be employed. Funnels and guide structures may be provided for guidelineless interfaces. Typically guidelineless techniques are employed in depths of approximately 500 meters and greater.



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3.3.6


Flow Assurance

The following flow assurance features can be applied to subsea production manifolds: • • • • •

Insulation. This can include insulation of the trees, valves, flowlines and headers. Pigging. The piping can be designed with pigging tees, long radius bends (3D to 5D radius depending on pig type) and pigging valves so the pipelines and headers can be pigged. Chemical injection can be provided. A chemical injection header and valves can be provided. The chemical is usually provided via the production umbilical. Heat tracing. While not commonly done, heat tracing can be provided on the manifold piping. Subsea Multiphase Pump. A booster pump installed on the manifold to provide more delivery pressure into the production flowline. This is relatively new technology that shows promise for long tie-backs, low pressure reservoirs and higher viscosity fluids.

ROV Valve Actuator Buckets

Flowline Attachment Point

Figure 3.11 - Another View of a Typical Deepwater Pipeline End Manifold (PLEM)



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3.3.7


Deep Water

An important design consideration for subsea manifolds and templates in deep water is the method of installation. The installation method must be considered early during the equipment design and appropriate installation aids included. In particular, the deep water compounds the difficulty of positioning and leveling of the template, and the designer or installation contractor needs to provide a means to maneuver the template into position, to orient it in the right direction and once set on the bottom, to level it. It may be necessary to set clump weights nearby and use pull-in lines to aid with the maneuvering of the template. ROVs may be used for observing the maneuvering and leveling operations, and can be used for connecting messenger lines, actuating hydraulic devices, etc. ROV access is critical in deep water. Horizontal and vertical access and connection systems for flowlines and ROV tooling are routinely used. Valve interfaces should be arranged at or near the same interface plane with common interfaces if possible. Grab handles can be provided for stabilizing the ROV while it conducts its work. Uniformity of interfaces and commonality of intervention tooling is ideal. Integration testing using a mock-up of the ROV is often useful. Intervention tooling must be integration tested by interfacing with the subsea hardware before deployment. For the components of subsea manifolds and templates the deep water design considerations are the same as those discussed in Section 2.3 for subsea Christmas trees. 3.4

Tree ROV Jumper

Flowline Jumper Connector

Umbilical

Figure 3.12 - A Four Satellite Well Cluster Tied Into a Manifold With Rigid Pipe Jumpers.



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Ancillary Equipment 3.4.1

Valves

The individual flowline branch valves employed on subsea manifolds are often identical to the types of valves used on subsea Christmas trees. Larger header valves may be specially designed for manifold service. Ball valves developed for subsea pipelines are often used in the larger sizes. Valves used for subsea manifold service are typically designed, fabricated and tested in accordance with API 17D, API 6A and API 6D. Subsea valves are typically furnished with manual (ROV) actuators or hydraulic actuators. For critical service the hydraulically actuated valve may have a ROV override. ROV operated valves should have a visual position indicator. Manifold valve service is usually less critical than subsea tree service, in that a small amount of valve leakage may be tolerable. Also, manifold valves may be designed to fail open, whereas subsea tree valves are nearly always designed to fail closed. A combination of fail open and fail closed valves may be provided in the manifold piping so that a control system failure will allow production to continue uninterrupted in a safe mode and/or flowline pressure management – typically for hydrate prevention after a shut down. Large valves may have double acting actuators that fail “as is”. Manifold valves are usually full opening. Header valves often must be piggable and the bore must be smooth and may have to be closely matched to the inside diameter of the flowline and header piping. The manifold valves and the actuators must be designed for high hydrostatic pressure in deep water service. Hyperbaric testing is recommended. Pressure balanced actuator designs help to mitigate the effects of hydrostatic pressure, but testing is essential to identify unanticipated effects on seals, unrecognized leak paths and such. Subsea tree valves rated for 10,000 psi are commonplace. As more subsea trees are designed for 15,000 psi, high pressure valves in smaller sizes will become more available. High pressure valves (10,000 and 15,000 psi) in larger sizes lag in development. Availability of valves in the required pressure rating needs to be considered when conceptually planning the manifold performance requirements.



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3.4.2


Chokes

Chokes are flow control devices designed to take the rigors of high pressure drop and high fluid velocities through the ports and across the seats. They are normally provided on the individual well flowlines, and are designed to control the flow and pressure from the wells into the manifold. They may be mounted on the manifold or on individual trees.

Figure 3.13 - Examples of a Non-Replaceable Subsea Choke Adjustable chokes provide flexibility for start up and commingling of fluids from different wells and are commonly used. Chokes can also be used for controlled well shut ins to prevent cutting across critical sealing valves at high flow rates. Chokes are not expected to be completely pressure tight and act as full flow shut off mechanisms though they often are capable of complete shut off until they wear. Due to the effects of erosion they often experience wear, and occasionally require replacement. Some subsea chokes are designed to close rapidly for the purpose of saving the critical pressure retaining valves by closing before the valves do thereby eliminating potential cutting across the valve as it closes with high flow. A fully adjustable choke actuator is a complicated part of the choke assembly with many moving parts and sometimes proves to be the part of the choke that wears out first requiring replacement before the choke trim. Choke actuators normally include a means of ROV override to allow the choke to be adjusted manually if the actuator fails. Choke actuators normally come in two design categories. They are either Stepping or Rotary drives. Stepping chokes are robust and provide very accurate trim adjustment but are slow and take significant times to open and usually to close. They may take 100 or 200 or more control pressure cycles to actuate the ratchet and pawl stroke mechanisms to fully open or close the choke. This can often take half an hour or more to fully open or close the choke. Rotary actuators are much quicker but less accurate and less robust than the stepping actuators. They are also smaller and cheaper. At high pressure, the flow rate is very sensitive and requires adjustment accuracy. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Hydraulic and ROV actuated chokes are both usually provided with a visual position indicator. In addition, hydraulically actuated chokes are normally provided with a position transducer. There are a variety of choke trim designs and each has useful application for flow control depending on numerous factors such as fluid composition, flow rates, pressures, accuracy of control requirements, debris content, bi-directional flow requirements and others. The varieties of trim design include Plug and Cage, Orifice and Bean, Rotating disk or Plate, and others. Choke trims are normally coated with hard wearing material such as Tungsten carbide to prolong the life of the trim. Trims are sometimes designed so that the high velocity fluid impinges upon itself in the turbulent area of flow in the choke to also assist to prolong the life of the trim. Reverse flow or even reverse pressure differential can damage some choke trim designs and thus if the possibility of this occurring exists, alternative designs should be selected. Instances where this can happen occur in fields where multiple wells are commingled into a single flowline or even during flowline commissioning pressure testing. Subsea chokes are routinely designed and built to enable the remote replacement of the choke internals and actuator without retrieving the rest of the subsea hardware. The main outer body of the choke remains in place fixed to the piping on the subsea hardware. The choke internals or “choke insert” can be removed and replaced with a dedicated tool and ROV. The retrievable choke insert is designed as a module that can be installed and removed using a running tool. These are sometimes run on guidelines, but in deep water are usually guidelineless and directed into guidance funnels by ROV. An alternative simple choking device that is often employed on subsea trees is the orifice choke. This is a gate valve with a small orifice in the gate position that would normally be the closed position on the gate. The orifice choke is used for well start up, to prevent dramatic and damaging draw down across the reservoir, and to slowly pressurize a flowline. The actuator is then functioned to fully open the choke – by moving the gate to the full open position. Orifice chokes are not normally remotely replaceable as insert chokes.



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3.4.3


Flowline Connectors

Flowline connections to manifolds in deep water may be done by a diver in an ADS, by ROV, by a remotely operated retrievable tool, or by a combination of all these methods. The following types of connections may be employed: • • • •

API flange (fixed or swivel) with SBX or SRX gasket. These work best arranged vertically with guide funnels for capturing and guiding the flange into position. API hub and clamp per API 16A, or proprietary version of same. The segmented clamp is sometimes mounted on a carrier plate with an ROV actuator. Proprietary mechanical connector, such as a collet style connector, similar to that used for a wellhead connector, but smaller. Multi-bore connector. A proprietary mechanical connector design for connecting a pipeline bundle. These involve complex sealing requirements between adjacent bores and are expensive.

Figure 3.14 - A Variety of Horizontal Flowline Connectors

Figure 3.15 - A Vertical Flowline Connector See Section 4.2 for more discussion of flowline tie-ins and jumpers. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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3.4.4


Flow Meters

Flow meters in subsea applications are still a relatively new concept. The main benefit of subsea flow metering lies in the ability to meter flow at the manifold before commingling, and avoiding shut-in of adjacent wells for well testing or installing a separate well test flowline. The most promising multiphase flow meters employ a gamma ray source passing through a thoroughly mixed and homogenized stream of fluid, and inferring from the signal detected on the other side of the stream the relative fractions of oil, water and gas.

3.4.5

Sand Monitoring

Sand erosion in subsea production equipment can be very destructive, resulting in catastrophic failures. Subsea monitors can warn of excessive sand production before too much damage is done. There are several types. One method commonly used in subsea applications relies on acoustic signals generated by the particles impinging on the walls of the piping. It is typically installed immediately past a bend in the piping. It can be strapped onto the pipe and hence can be retrofit to the subsea production system. A disadvantage is susceptibility to flowline noise, such as might occur near a flowline choke. Other sand and erosion monitoring systems are based on measuring the change in electrical resistance of thin sensing elements which are eroded by sand. The system reads the erosive effect directly and is highly resistant to acoustic noise from pumps or variable flow. There is no need for calibration, and the system is particularly sensitive to cumulative erosion over time. Several sensor strips are used for redundancy and to cover the entire cross section of the pipe. The probe is read by sophisticated electronics. The 'raw' data are corrected using a reference element located on the back side of the probe. Software tools can predict worst case erosion on critical pipe elements such as chokes or bends based on erosion measurements or sand production data from other applications.



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4


SUBSEA SYSTEM INTERFACE REQUIREMENTS

Successful management of subsea projects is largely a matter of managing interfaces: physical, functional and organizational. The subsea equipment designer needs to consider installation and future intervention issues such as diver access and ROV tooling compatibility. Control systems must interface with subsea production equipment, drilling rig equipment and host production facilities, both physically and functionally. Drilling, completion and workover planning needs to anticipate the subsea production equipment requirements. The drilling rig equipment and personnel need to be properly prepared for the installation of the subsea equipment. • • • • • •

4.1

Early planning, frequent communication and methodical integration testing will help avoid costly surprises later. This section addresses the physical and functional interface requirements of a subsea production system. The interface areas addressed are: Controls and Umbilicals Flowline Tie-Ins Installation and Workover Risers System Commissioning and Startup

Production Control System

By its nature a subsea production system consists of a collection of discrete components. Since the components of a subsea production system are inaccessible for operator intervention and must work together in a coordinated manner, it is necessary that they be controlled remotely with an integrated control system. The control of the components of a production system is managed by the subsea production control system. The control functions include the following: • • • • • •

Opening and closing subsea tree production, annulus and crossover valves. Opening and closing the SCSSV. Opening and closing subsea production manifold flowline valves and pigging valves. Opening and closing chemical injection valves. Adjusting subsea choke position. Monitoring pressure, temperature and other data from tree-mounted, manifoldmounted or downhole instrumentation.

The following are some of the key design issues that must be considered when specifying or designing the subsea control system: • • • • • • •

Offset distance. Distance affects signal strength, hydraulic pressure loss, response time and cost. Valve control requirements: The number of valves, types of valves, types of actuators, size of valves, failure position of valves. Chemical injection requirements. Valve operation, umbilical sharing. Instrumentation requirements: Pressure or temperature monitoring, pig detection. Installation and workover requirements and interface with the IWOC system. Redundancy requirements. Expandability. Future wells, future flowline tie-ins.



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4.1.1


Types of Control Systems

There are four basic types of production control systems: • • • •

Direct Hydraulic Control System Piloted Hydraulic Control System Electro-Hydraulic Piloted Control System Electro-Hydraulic Multiplexed Control System

Manufacturers are also developing all electric control systems, but they have not yet been applied commercially.

Figure 4.1 - Example of a Direct Hydraulic Control System HPU and Panel for Six Subsea Wells

4.1.1.1 Direct Hydraulic Control System The direct hydraulic control system is the simplest and least expensive production control system. It consists of a topside Hydraulic Power Unit (HPU) with one dedicated control line for each remotely actuated valve on the subsea tree. This type of system is typically recommended for 1-2 well tiebacks within 3 miles of the host platform. The advantages of this type of system are: • •

Simple and inexpensive. Easy to maintain and diagnose problems.

The disadvantages of this type of control system are: • •

Umbilical tube required for each valve function. Slow response time.



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4.1.1.2 Piloted Hydraulic Control System The piloted production control system is similar to the direct hydraulic control system, except that the valve that requires fast closing time will have a pilot valve and will vent to sea upon closing. The advantages of this type of system are: • • •

Improved response time for the critical valve. Extends the offset distance possible for direct hydraulics. Allows use of smaller umbilical tubes for the pilot operated functions.

The disadvantages of this type of control system are: • • •

Higher cost than direct hydraulic system. Umbilical tube required for each valve function. Response time still limited by offset distance.

4.1.1.3 Electro-Hydraulic Piloted Control System The electro-hydraulic piloted production control system is used for medium offset subsea well tiebacks. This system consists of a topside electrical and hydraulic control system tied to one or more service umbilicals to the field. Each tree, well center or manifold has a subsea control module (SCM or pod) which takes LP and HP supplies and directs them to local valves when commanded by the topside system. The advantages of this type of system are: • •

Improved response time for critical valves Greater offset distance than hydraulic piloted system.

The disadvantages of this type of control system are: •

Higher controls equipment cost than hydraulic piloted system.

4.1.1.4 Electro-Hydraulic Multiplexed Control System The electro-hydraulic multiplexed (EH-MUX) production control system is used for medium to long offset subsea well tiebacks where there are numerous subsea wells, well centers or manifolds with many functions. The EH-MUX system consists of a topside electrical and hydraulic control system tied through a service umbilical to one or more trees, well centers or manifolds. Each end device or node in the system has a subsea control module (SCM or pod) which receive the multiplexed electrical control signals and the LP and HP hydraulic supplies and directs them to control tree or manifold mounted valves or other functions when commanded by the topside system. This system is common in large multi-well deepwater developments. Its main advantage is the use of a multiplexed electrical control signal over a single pair of conductors, resulting in a smaller control umbilical. This system accommodates future expansion easily and reduces umbilical costs significantly.



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Comparison of Control System Types System Type Direct Hydraulic

Major Components • HPU • Control Panel • Umbilical

Piloted Hydraulic

• Control Panel • Umbilical

ElectroHydraulic Piloted

Pilot

• HPU • Control Panel • Umbilical • Subsea Pod

Multiplex ElectroHydraulic

• Simple • No Subsea Pods • High Reliability

• HPU

• Subsea Valve

Advantages

• Control Panel • Umbilical • Subsea Control Pod

• Proven Reliable

• Costly Miles

• Quick Response For Selected Tree Valve

• Subsea Equipment

2-5 Miles

• Medium Distances • Satellite Trees

>

5 2 – Miles

15

• Large Umbilical • Costly Miles

• Smallest Umbilical

• Small Fields • Local Manifold

• Large Umbilical

• Subsea Data Feedback

0-3 Miles

Typical Applications • Single Satellite • Short Distances

• Reduced Umbilical

• Fastest Response

Range

• Large Umbilical • Subsea Equipment

• Greatest Flexibility

4.1.2

• Slowest Response

• Improved Response

Mini

• HPU

Disadvantages

>

• Long Distances • Satellite Trees • Minimum Feedback

15

• Complex

5 Miles +

• Long Distances

• Subsea Equipment

• Data Feedback

• Subsea Electrical Connection

• Remote Manifold

• Costly Electronics

• Large Templates

• Complex Fields

Production Control System Components and Functions

The following is a description of an electrohydraulic multiplexed production control system.

4.1.2.1 Topsides Control Unit (TCU) Control of the subsea production system is managed by the Topsides Control Unit (TCU). The TCU is generally made up of three main components, the Master Control Station (MCS) the Electrical Power Unit (EPU) and the Hydraulic Power Unit (HPU). It should be noted that terminology and acronyms may vary from one supplier to the next.



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Master Control Station (MCS) The MCS is the “Master Control Station” which provides power, control logic and communications for the subsea control system. The MCS also provides the man-machine interface (MMI) for the control system. The MMI consists of a microprocessor based control system, display screen and keyboard for the operator to monitor the system and input and retrieve data. The MCS has the following main functions: • • • •

To condition the topside electrical power supply to provide independent, electrically isolated, protected and regulated, single phase power to the subsea control modules. To condition the topside electrical power supply to provide two redundant, electrically isolated, protected, and regulated single phase power sources to the subsea control modules. To provide the conditioning of the control signals into a format suitable for transmission though the conductors of the umbilical, compatible with the modem of the subsea control module. To combine these two signals into a form that can be transmitted together on a single pair of conductors within the umbilical.

The MCS consists of a computer (or a serial interface with the platform DCS computer), power conditioners, modems and multiplex/de-multiplex (mux/de-mux) circuits. The mux/de-mux circuits process the signal data so it can be transmitted over the same conductors that carry the electrical power. The output from the mux/de-mux to the subsea control system is typically a maximum of 600V.

Figure 4.2 - A Master Control Station (MCS) for a Multiplexed Subsea Production Control System Two power channels within the MCS convert the power from the topside supply. It is then at a level for transmission through the umbilical to the subsea control modules. Components in Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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each output channel are identical and completely separate. Power modules, controllers and other components can be removed from one channel without affecting any other. A line insulation monitor is incorporated on each power module to provide protection against insulation faults in the channel output line. The line insulation monitor has two alarm levels at adjustable resistance settings. At the first level an alarm signal is issued to the master control computer. At the second, lower impedance, the affected power supply is isolated and a secondary alarm generated. The outputs from each channel are electronically protected against over voltage transients and over current. The voltage and current for each output are displayed on the controllers’ front panel and transmitted to the master computer for display. Both the power channel outputs and the modem line connections interface with the umbilical via a power and signal combiner. A combiner is required for each channel. The communications circuits are bi-directional for both up-link and down-link transmissions. An output circuit breaker is fitted on each combiner. Electrical Power Unit (EPU) The EPU provides electrical power for the subsea control modules (SCMs). Power is generally supplied from a topside power supply with battery backup (UPS). The EPU monitors status of the dual redundant power circuits in the umbilical, and allows a circuit to be

Figure 4.3 - Typical Electrohydraulic Subsea Production Control System Topsides Components isolated in case of damage. Filters and modems in the EPU allow communication signals between the MCS and the SCM to be transmitted over the same circuits that are used to transmit power. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Hydraulic Power Unit (HPU) The HPU supplies low pressure (LP) and high pressure (HP) hydraulic control fluid to the system. It includes a hydraulic fluid reservoir, hydraulic pumps, hydraulic accumulators, pressure regulators pressure gauges, flow meters and other instrumentation and controls. The HPU usually has redundant HP and LP pump and filter systems. The HPU is to be designed for use in the appropriate platform hazardous area classification. The hydraulic system uses water based control fluid. Typical control fluid cleanliness requirement is NAS 1538 class 6, although all components within the hydraulic system should operate satisfactorily up to NAS 1538 class 10. • • • • • • • •

A hydraulic analysis should be performed when a field’s architecture becomes available. The key hydraulic considerations are: Field layout (distances between wells and to the host). Number of hydraulic users (valve actuators, chokes). Pressure requirements (HP and LP systems). Umbilical characteristics (tube size, tube material, elasticity, fluid compatibility). Actuator characteristics (volume, pressure opening speed required, closing speed required). Number of open/close cycles in a given time period to design for. Platform features (umbilical routing, elevation above water).

The hydraulic distribution system for the EH-MUX system is open loop with valve actuator returns vented to sea via a relief valve in the SCM. Valve Signature Emulator (VSE) The TCU sometimes will include a Valve Signature Emulator. The VSE records and monitors the pressure versus displacement characteristics of the hydraulic actuation of the subsea valves. Each valve will have its own unique signature. Using this signature data, the behavior of valves during actuation may be monitored and malfunctions such as leaks, incomplete actuation or sticking actuators may be detected.

4.1.2.2 Subsea Control Module (SCM) The SCM is the interface between the control system and the various end users, such as tree valve actuators, manifold valve actuators, transmitters, downhole valves, smart well functions, etc. A SCM may be installed on a subsea tree, a manifold, a template or other component. One SCM can manage dozens of functions as well as digital and analog inputs. Individual SCMs may be linked together by control umbilicals and controlled as a single large integrated system. The SCM is usually designed to be replaced using either a running tool or ROV. All electrical jumpers can be pre-installed, parked on the templates or trees, subsequently connected by ROV, and can be replaced by ROV if required. The SCM is normally installed with the tree or manifold, but may be recovered separately. The SCM is a self-contained, pressure compensated “pod” consisting of a rectangular cylindrical housing containing control valves, sensors and subsea electronics modules. The lower base plate is usually integral with the tree frame or manifold structure. The base plate is the interface for all hydraulic functions. The SCM is usually filled with a dielectric fluid that acts as a secondary barrier against the ingress of seawater. Power supplies, signal supplies and remote sensor connections are made up via ROV umbilical connectors. The connectors are high integrity controlled environment connectors Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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with dual oil filled barriers protecting the contacts. Either Tronic or Ocean Design Inc. manufacture most of the subsea electrical connectors currently in use. Electrical connectors housings can be manufactured from duplex stainless steel grade UNS 32550, titanium or other suitable alloys. Typically the non seal containing half (male pins) are mounted to the permanent subsea structures. Within a project, it is best to standardize on one SCM design for all trees and manifolds if possible.

Lockdown Mechanism

Electrical/Optical Accumulators

Connectors Subsea Electronics Module

Control Valves and Manifolds

Hydraulic Couplings

Figure 4.4 - Typical Subsea Control Module (SCM)



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Figure 4.5 - Internal View of a Typical Subsea Pod – The Outer Housing Is Yet To Be Installed



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4.1.3


INSTALLATION AND WORKOVER CONTROL SYSTEM (IWOCS)

The subsea production control system provides the means to control subsea trees during the day to day production operations. The Installation and Workover Control (IWOC) System provides control during installation, workover or other intervention operations. The IWOC system is an essential consideration in the design of the overall subsea tree controls and involves many interfaces. As with the production controls, there are four main types of workover control systems. These are, direct, piloted, electrohydraulic (EH), and electrohydraulic multiplexed (EH-MUX) systems. The most common are the direct and multiplexed systems with the others being considered to be older technology. The IWOC system must integrate with the production control system on the subsea tree and in many ways mimics the production control system to allow the rig control of the tree during installation or workover operations. The components are much the same. When first installing a tree, the rig must control the tree connector, valves for circulation, running tool hydraulics and other functions. If the production system is not yet available from

Figure 4.6 - A Typical Surface Make-Up Subsea Umbilical Termination the host production facility the rig must provide all power and control. If the production control system is available, the option to use the production umbilical for power is available. Philosophically, most (but not all) operators dictate that when a rig intervenes on a subsea tree, this action disables the platform from controlling the tree. This is particularly important on trees with valves in the vertical bore, such as dual bore trees, because the rig would never want the platform to inadvertently open or close a valve on the tree while the rig was working on it. Closing a valve could cut wireline or coiled tubing that could be in the well, while Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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opening one could unexpectedly bring well pressures and fluids to the rig. There is less risk with horizontal trees because there is no tree valve in the vertical bore. The lockout of control can be accomplished in a number of ways. Conventional tree designs have a tree cap with all the key hydraulic functions usually passing through a junction plate in the cap. When the cap is removed, it disables the platform controls to the tree by breaking the control circuits. When the tree running tool, lower marine riser package (LMRP) or other

Figure 4.7 - A Typical Remote Make-Up Subsea Component Hydraulic Interface interface is mated to the top of the tree, hydraulic functions are re-established to the broken circuits and control is now with the rig. If the IWOC connection is by flying lead, a similar principal can be applied with a “bridging plate” or “logic cap” that, when removed to allow the IWOC control umbilical to be plugged in, also breaks the circuits controlled by the platform. These two methods of transferring control circuits are usually employed when an EH-MUX

Figure 4.8 - Another Type Of Remote MakeUp Hydraulic Interface

system is used on the tree. The tree cap or bridging plate circuitry normally disrupts the hydraulic pod (or subsea control module) outputs so that the pod is rendered ineffective. In direct hydraulic controlled systems, the production control umbilical or flying lead from it is normally unplugged to allow the rig controls to plug into the tree. This thereby transfers control from the platform to the rig. The hydraulic power unit (HPU) is the source for hydraulic pressure and power. The HPU will often include a control panel for directing hydraulic power as required. Larger systems may have a separate control panel. Direct hydraulic systems require a complex panel with panel Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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mounted valves, gauges, hydraulic tubing and relays. An EH-MUX system relies on a computer as the control interface. The HPU typically includes a number of accumulators to store hydraulic power. These help to speed up response time when opening valves and prevent the pumps from stopping and starting continuously to compensate for pressure bleed-off. In addition to the main IWOC panel, some control functions may be included on the umbilical reels and often the side of an IWOC umbilical reel will be a mini panel. Hydraulic functions that are required to remain “live” (such as a tree running tool or tubing hanger running tool) during the spooling out of the reel will be controlled on the reel. A single supply line can be connected through a swivel at the axis of the reel and distributed to the appropriate hoses in

Figure 4.9 - A Typical IWOC HPU Panel

the umbilical through the reel mounted panel. After deployment of the umbilical the main supply jumper can be hooked up. EH-MUX systems can be controlled during installation or workover by a computer and electric down line (umbilical) plugged into the pod on the tree. Hydraulic power must also be supplied to the tree in order to provide motive power for the actuators on the tree. As mentioned earlier, this can be supplied through an IWOC hydraulic umbilical that is run from the rig or if the production umbilical is available from the host production facility. During workover, it is often preferred not to break any of the hydraulic circuits from the production control umbilical because they are known to be functional and pressure tight. An EH-MUX system is highly suited to this principle in that the system can be designed such that plugging in of an electric down line will disable the control from the host production facility. This can be accomplished by unplugging the electric line from the production umbilical to plug in the down line. Alternatively, it can be done by having a separate IWOC receptacle on the pod and building into the pod the logic that prevents it from acting on any instruction it receives from the production host while a down line from another computer is plugged into it. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The IWOC system also controls the LMRP and EDP for a conventional or mono-bore tree system. The IWOC system provides the controls and umbilical to operate the tubing hanger running tool, perform seal and gallery tests within the tree system, and the means for chemical injection for the tree and down hole as required.

Figure 4.10 - A Typical IWOC HPU and Reel System

Figure 4.11 - A Typical Output Plate From an IWOC HPU Panel

Proper placement of the IWOC on the rig is important for running the umbilicals. The umbilicals are passed from reels through roller sheaves above the point where the umbilicals go down into the riser or splash zone. The umbilical reel needs to be located within line of sight of the sheave. The sheaves must be securely attached because the weight of the umbilical will be supported by them. It is good practice to have sheaves certified with a proof load and include weld NDE and load testing of the mounts. The HPU can be located anywhere because the hydraulic power can be relayed or distributed to the various reels by hoses as required. The HPU is distributed to the umbilical and reel Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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through jumper hoses that may run around the deck of the rig. The umbilical reels are typically air powered for paying out and hauling in the umbilicals. They should include a fail safe brake that is released when air is supplied to the drive motor.

Figure 4-12 - Typical Input Plate to an IWOC Reel



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4.1.4


Umbilicals And Flying Leads

The umbilicals and flying leads provide the interface between the topsides control system and the individual subsea components.

4.1.4.1 Topsides Umbilical Termination Assembly (TUTA) The TUTA gathers the hydraulic supplies hoses from the HPU and the electrical and signal cables from the MCS and provides a connection interface with the umbilical. The TUTA has a junction box for termination of the umbilical electrical conductors and the platform cabling from the MCS. A set of valves can be added to this box for umbilical commissioning purposes. That allows filling and flushing of all umbilical lines from one point on the host.

Figure 4.13 - An Example Of A TUTA –Topside Umbilical Termination Assembly– The Subsea Umbilical Starts At This Box On The Production Facility. The HPU Ties Into This Point To Supply Hydraulic Power. This unit goes by other names and acronyms, such as Topside Umbilical Termination Box (TUTB), Umbilical Junction Box (UJB), Production or Platform Umbilical Termination Assembly (PUTA), etc.



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4.1.4.2 Umbilicals The main functions of a subsea production umbilical are: •

To deliver hydraulic or electrical control signals to subsea control devices such as pilot valves, solenoid valves or relays. To provide power for subsea actuators or motors, either hydraulic or electric. To convey injection chemicals to subsea trees or manifolds. To monitor well annulus pressure.

• • •

Umbilical Tube Materials There are many options for umbilical tube materials. They include, but are not limited to, duplex stainless steels, thermoplastic hose, zinc coated carbon steel tube, and other alloys. Material selection is dependent on a number of factors, including pressure rating, chemical resistance, water depth and cost. The following table is a simplified application guide for umbilical tube materials.

Material THERMOPLAS TIC HOSE

Pressure Limitations

Most chemicals. Methanol may permeate Nylon 11 liner.

Limited water depth.

Most chemicals. Methanol may permeate.

Unlimited

15,000 psi for ½” tube

Most chemicals.

Unlimited

10,000 psi for up to 1-1/4” tube

Most chemicals. Hydraulic fluid cleanliness a possible issue.

Unlimited

10,000 psi for 3/8” hose

High Collapse 10,000 psi for Resistance 3/8” hose (HCR) Hose Super Duplex Stainless Steel

Carbon Steel

Water Depth Considerations

Services

Note: This table is a guide only. It is recommended to check with suppliers.



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Cross Section Design

Cross section design of umbilicals is dependent on the tube size, tube material selection, desired hydrostatic resistance, desired dynamic characteristics and installation issues. For long offset distances weight can become an important factor. The umbilical must be handled by the manufacturer and transferred to the installation vessel. The installation vessel must have the weight capacity, and installation tensions can be very high, especially for steel tube umbilicals.

Figure 4.14 - Umbilical Armour Pot



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Umbilical Design Interface Issues

Umbilical Supplier

• Umbilical manufacturing and QA requirements. • Commissioning and installation activities support. • Umbilical shipping and transfer to installation vessel.

Host Facility

• Offset distance. • Hang off dynamic requirements. • Hang off weight. • Cathodic protection or insulation issues. • Interface to platform mounted TCS. • Commissioning and installation activities. • Chemical injection system design.

Umbilical Installation Contractor

• Umbilical handling. • Installation vessel reel capacity. • Installation method and limitations of umbilical.

Subsea Umbilical Termination The ends of the umbilical are fitted with umbilical terminations. The end terminations are designed to take the installation and hang-off loads imposed on the umbilicals. A common method of transferring the imposed loads into the umbilical is through the use of an armour pot. The pot interlocks with the armouring or other structural components in the umbilical without loading the hoses. End accessories can then be mechanically fitted to the armour pot. The end termination often includes a bend restrictor to prevent excessive bending stresses at the connection during service or installation. Individual cable terminations are commonly fitted with caps offering protection during deployment. The caps may also feature resistive loads between the individual pins to enable monitoring of the umbilical conductors for any faults during installation. Hose connections are also fitted with protective caps. The hydraulic caps may also contain loops to facilitate umbilical commissioning.



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Umbilical Splices Umbilical splices are successfully and routinely used, particularly on very long umbilicals. They must be well designed and correctly installed. If not, they often represent weak points and frequently turn out to be the source of water ingress leading to electrical failures and hydraulic leak points. They can be very reliable, but as a general rule, should be avoided where possible, as they are a potential source of failure. Splices are a useful means of repair to a damaged umbilical, and enable very long umbilicals to be created and installed from shorter flaw free lengths. Unplanned field splices are time consuming to install during an umbilical installation procedure and should be conducted under the close supervision of a representative of the umbilical manufacturer. Planned field spices can be preinstalled on umbilical lengths to minimize field splice make-up time.

Figure 4.15 - Umbilical Splice Connections. Left Photo is a Planned Field Quick Make Up Splice Kit. Right Photo is a Permanent Factory Splice -It Is Similar To a Repair Splice- the Cover is Not Installed.



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Umbilical Integration Testing It is beneficial, after the completion of umbilical FAT (factory acceptance test) and the controls components have completed their testing to bring the system together. This testing usually involves multiple suppliers and verifies that interfaces are correct before installation activities begin. The components included in this test are normally the topside control system simulator, the production umbilical, the hydraulic/chemical jumpers, the electrical jumpers and the subsea control module (pod).

Figure 4.16 - System Integration Testing of A Thirty-Mile Long Control Umbilical.

Reference Standards Standards governing the material selection, manufacturing and testing of umbilicals include API 17E and ISO 13628, Part 5.



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Umbilical Termination Assembly (UTA) The subsea end of the umbilical is terminated with the UTA. The UTA serves to secure the umbilical and provide an interface to the umbilical flying leads. It can also serve as an installation aid for lifting and handling the free end of the umbilical and lowering it to the seabed. The UTA often includes a sled-like structure designed for resting on the soft seabed and securing the end of the umbilical. The electrical and hydraulic flying leads are connected from the UTA to the subsea tree, manifold or other end device.

Electrical Connection Points Bend Restrictors

Flying Lead

Figure 4.17 - A Typical Subsea Control Umbilical Termination Assembly For Two Subsea Wells. Note The Hydraulic Flying Lead Plugged Into One of The Hydraulic Junction Plates. Note The Electrical Connection Points.



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For a complex system the UTA might be broken down into a number of sub-components consisting of an umbilical termination head (UTH), electrical distribution unit (EDU) and the hydraulic distribution module (HDM).

Figure 4.18 - A More Complex Umbilical Termination Assembly for Several Wells –Note the Electrical Connections Are Not Included In This Sub Assembly.



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4.1.4.3 Electrical Distribution Unit (EDU) The EDU provides electrical distribution to a number of end devices, such as individual subsea trees on a template. The EDU is an oil filled and pressure compensated enclosure, within which the incoming electrical power and electrical signals are distributed to two or more satellite SCMs. More than one EDU may be chained together, with each EDU serving a number of satellite SCMs.

EDU

Hydraulic Junction Plates

Figure 4.19 - Example of a Large Umbilical Termination Assembly with a Large EDU Included.



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4.1.4.4 Electrical Flying Leads Electrical flying leads (EFLs) provide the electrical interface between the umbilical termination assembly and the subsea tree (or other end component). There are often two redundant electrical flying leads from the UTA to the end component. The electrical conductors are usually run inside oil filled hoses. The electrical contacts are protected by dual oil filled barriers. Electrical flying leads are easily installed by ROV. They can be coiled and stowed on the equipment before deployment and uncoiled and installed by the ROV after deployment.

Hydrostatically Balanced Dielectric Oil Filled Cable

ROV Connectors

Figure 4.20 - Diagram Of an Electrical Flying Lead with Typical ROV Wet MateAble Electrical Connectors



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4.1.4.5 Hydraulic Flying Leads Hydraulic flying leads (HFLs) provide the hydraulic (and chemical injection) interface between the umbilical termination assembly (or hydraulic distribution module) and the subsea tree (or other end component). The most commonly used and easily maneuvered hydraulic flying lead is made with thermoplastic hose. The individual hoses are terminated at a junction plate with low force make-up, self-sealing, hydraulic couplings. The hoses are typically constructed with Nylon 11 liner material, braided Kevlar® reinforcement and two outer layers of extruded thermoplastic material. Monel® hose end fittings are permanently swaged onto the hose.

Figure 4.21 - Picture of a UTA with A Hydraulic Jumper during Systems Integration Test. For deep water applications a new high collapse resistant hose has been developed. High collapse resistant hose is steel reinforced to prevent the collapse of the hose in deepwater. The flying leads are stiffer than those of Kevlar® reinforced hose, but can be deployed in a similar manner. Another type of hydraulic jumper is the steel flying lead (SFL). The steel flying lead is a bundle of steel alloy tubes terminated into couplers on a junction plate. Most designs use super duplex stainless steel material for its high strength. This allows thin wall construction for flexibility. Even so, the steel flying lead is stiffer than the thermoplastic flying leads. Deployment may require additional tooling besides just the ROV. Various deployment kits exist to lay the steel flying lead like a small umbilical. Once the lead is deployed, the ROV can complete the end connections.



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4.1.4.6 Hydraulic Junction Plates The hydraulic flying lead connects at either end by means of hydraulic junction plates. Junction plates consist of two halves, one on the flying lead, and a mating half on the other component (subsea tree, manifold, umbilical termination assembly, or hydraulic distribution module). The junction plates on the hydraulic flying lead are designed with ROV buckets so an ROV can connect to them, disconnect them from their pre-deployment “parked” position, maneuver them into position for connection to their mating connectors, and effect the connection, usually by means of a rotary torque tool which drives the two junction plates together and effects the mating of the individual hose coupling halves on each junction plate. Junction plates often employ low force couplings that can be mated under pressure, though balancing of forces may have to be considered in such a case. The coupling seals are typically on the recoverable half of the junction plate (i.e. the flying lead).



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4.1.5


ROV Interface

4.1.5.1 General Remotely Operated Vehicles are commonly referred to as ROV’s. These are remotely controlled unmanned submersible robots – submarines. They are available in a variety of capabilities and sizes. The most basic ROV is merely a camera carrying vehicle with thrusters to drive it to location under water. Larger work class ROV’s include many cameras, manipulator arms with a variety of capabilities, numerous thrusters, sonar, and other sensors. They are available with a variety of different depth ratings. ROV’s are controlled from a central computerized control room – often nicknamed the ROV

Figure 4.22 - Typical subsea mated junction plates with hydraulic couplings, where the inboard plate contains the male couplers and is permanently mounted. The outboard plate contains the female couplers and the ROV bucket for installation interface.

shack – with power and control signals passing through an umbilical to the vehicle. The umbilical stays permanently attached to the ROV. The deeper classed systems include a powered diving cage and tether management system to reduce current drag on a long umbilical system from the surface vessel. ROV’s can perform a wide variety of functions underwater. The only constraint is that most functions must have been pre-designed for ROV interfacing before the equipment is installed subsea. In addition to the manipulator and gripper functions, ROV’s can easily be equipped with special additional and often standard tool packages. These are designed to interface with the equipment being installed subsea. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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ROV interface is a system level issue as it affects almost all work packages and certainly all of the subsea installation, workover and intervention activities. There is effort within the subsea industry to standardize the ROV interfaces on all subsea equipment. To do this, the connection, handling, and marking interfaces must be the same on all subsea equipment. The specification that most manufacturers, ROV companies, and operators have followed for ROV interfaces is API Specification 17D. This specification was created based on the two most common interface standards that were present in the industry at the time of writing it. As such, and although a great deal has been standardized, the two standards were mixed together, and perfect standardization has not been accomplished.

4.1.5.2 Types of Interface There are several different categories of tools that a standard working ROV will use to interface with subsea equipment. These include: • •

Torque tools - There are five ranges of torque settings for overriding or mating of components subsea. The torques are assigned a Class rating per API 17D. Manipulator – Depending on how an ROV is outfitted, it may have a variety of “arms” for handling purposes outfitted with a variety of end “hands” called grippers. ROVs sometimes are equipped with one but often have two manipulators. The manipulators vary in complexity with varying degrees of freedom. It is common to have manipulators with a minimum of three axes or more. Five function manipulators, seven function manipulators and even nine function manipulators are available on the market.

Figure 4.23 - Standard ROV torque buckets -the end effector inside the bucket is difficult to see in these photos. The end effector size and shape determines the torque ratings for the bucket - note the optional grab handles on the panel in the right hand photo • •

Hot stab – The hot stab is used to introduce hydraulic fluid into a port for testing purposes, chemical injection, hydraulic power to actuate devices such as connectors or actuators. The fluid supply can often be arranged to come from the ROV package. Tool Deployment Unit (TDU) – The TDU facilitates secure docking of the ROV and precise X-Y indexing of tools for specific functions. The TDU can be configured to carry numerous small tools used to connect and disconnect flowline clamps, operate valves and undertake hot stab operations. The TDU can offer advantages over “free flying” of tools, particularly in strong currents. The disadvantages of using a TDU are that the ROV intervention equipment must be purpose built, requiring more interface engineering, and expense. Typical TDUs are shown in Figure 4-24.



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4.1.5.3 Testing Torque tools are commonly used during tree and manifold testing to verify torque values for functions on the actuators and to check for fit and accessibility. An ROV bucket contains two slots where the dogs on the torque tool latch in on both sides inside the bucket. The distance between the latching dogs and the nut to be driven is critical and is dictated by the API 17 D specification. Also, surrounding the bucket or likely, nearby

Figure 4.24 - Single Point Docking TDU (Left) and Twin Point Docking TDU (Right)

will be placed a grab bar. The grab bar can be used by the ROV to stabilize while attempting to engage or torque. Grab bars are also specified diameter. The valve or location is also to be marked in a manner to allow ease of visibility by the ROV camera, both upon initial installation and long term, for intervention purposes. The junction plates are also mated by ROV. The plates are made up using a torque tool inserted into the bucket and then the torque strokes the plate to mate the hydraulic couplings.

4.1.5.4 Manipulator Functions The manipulator serves as an arm and hand for the ROV. The manipulator can stabilize the ROV by grabbing onto the structure, turn the handles of small needle or ball valves, plug in electrical connectors, disconnect slings and rigging, and even tie knots.



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4.2


Flowline Tie-Ins

The following are some types of applications for subsea tie-ins.

Spreader Beam

Hydraulic Jumper Connectors

Insulated Hard Pipe

Figure 4.25 - An insulated hard jumper with flowline connectors at each end being deployed from a rig – note the spreader beam at the top.

• • • • •

Individual flowline connections between satellite subsea trees. Flowline connections from individual satellite trees to a subsea manifold. Flowline connections between one manifold and another. Departing flowline connections from a subsea production manifold to a production center. Connection between sections of production bundles.



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4.2.1 • • • • • • • • • • •


Flowline Tie-In Design Issues Installation method is a prime consideration of flowline tie-ins. The design is geared toward the installation method chosen. The installation method is dependent on the installation vessel and installation equipment availability. The number and size of flowlines. The design pressure and temperature of the flowlines. Flowline length or flowline jumper span. The seabed conditions such as temperature, visibility, topography and soil properties. Displacements, thermal cycling and flexibility requirements. External loads or installation loads likely to be imposed. Speed of deployment, actuation and recovery. Installation often takes place from vessels demanding high day rates. Minimum of equipment left subsea. A design with the hydraulics on the running tool is better than one in which the hydraulics are left in place when numerous connections are involved. Effects of hydrostatic pressure on installation aids (e.g. spreader beams with tubular members).

ROV PANEL

JUMPER PIPE

CONNECTOR MAKE-UP CYLINDERS

SOFT LAND CYLINDERS

TOP PLATE RING COLLET CONNECTOR ACTUATOR

RING ALIGNMENT FUNNEL HUB ALIGNMENT STRUCTURE

Figure 4-26 - An example of a vertical make up mechanical connector with hydraulic running tool



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4.2.2


Flowline Tie-In Methods

4.2.2.1 Jumper Tie-In Connection For tie-ins between satellite wells and flowlines, the flowline is commonly furnished with a Pipeline End Termination (PLET) that consists of a sled-like structure on the end of the flowline supporting the end fitting and sometimes a pipeline valve or small manifold (PLEM). The final connection to the tree is accomplished with a jumper. Jumper tie-ins may employ rigid pipe, flexible pipe and various connectors and installation techniques. The following are some variations: •

•

Hard pipe jumper using bolted flanges. The use of bolted flange connections dictates diver intervention and can only be employed within the limits of the ADS (about 750 meters). Its advantage is the hardware is relatively cheap. The tie-in flanges are usually oriented facing up. The distance between the flanges can be measured by a special Pre-Measurement Tool (PMT) that can be deployed by an ROV. The PMT uses a wire to measure the distance between flanges and the relative angles of the flanges. The jumper connection employs guide funnels to swallow the upward facing tie-in flanges. A guide sleeve arrangement aligns the flanges horizontally. One side of the connection employs a swivel flange for angular alignment. Bolts are extra long and tapered, nuts on the mating flange are captive to facilitate make-up of the flanges by the diver. Flexible pipe jumper using ADS and bolted flanges. Similar to hard pipe technique, but the use of flexible pipe allows less precise fitting of the jumper length to the span. Flexible pipe is advantageous where large relative movement is likely. A disadvantage is the high cost of flexible pipe jumpers.

Figure 4.27 - Typical Vertical Flowline Connector •

Hard pipe or flexible pipe jumper using hydraulic/mechanical connector. The connector in this case can be completely diverless. The PMT can be used as before to pre-measure the spool length. Actuation of the connector is hydraulic. In some connectors the hydraulics are part of the running tool, and in others the hydraulics stay behind as part of the connector. These can be actuated from the surface or by ROV.



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4.2.2.2 ROV Pull-In System Subsea intervention companies have developed a number of ROV flowline pull-in systems. The following is a description of a typical pull-in system (more details can be found in the specific chapters on Deepwater ROVs and Tools and Tie-In Systems). All the currently available pull-in systems share similar traits. • • • • • •

The subsea tree or manifold has a more or less horizontally oriented tie-in connection, usually oriented at an angle slightly below horizontal. A special pull-in tool is attached to the pipeline. It can be installed by the ROV. It includes a wireline winch. The ROV connects the pull-in wire at the other end of the connection. The winch is activated and the flowline ends are pulled together. Guide structures are employed to assist with the self alignment of the ends. Once the connection is engaged it is actuated by the ROV or hydraulically from the surface. A test port is sometimes provided for testing the seal integrity externally. It can be pressurized by the ROV.

Wires to surface Flowline or Manifold or Tree

ROV

Pulled In Flowline Figure 4.28 - Typical ROV Flowline Pull-In System Deployment



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4.2.2.3 Stab and Hinge-Over Tie-In The stab and hinge-over concept can be used for lay-away of a flowline from a subsea manifold or subsea tree flowbase. A receptacle captures the end of the flowline as it is lowered from the surface. A hydraulically actuated mechanical connector latches the flowline in place. As tension is applied the installation vessel moves away and an articulated joint allows the flowline to be hinged over and eventually laid down. After the flowline is in its resting position the seals in the articulated joint may be hydraulically energized. This obviates the need for dynamic seals in the hinge.

Figure 4.29 -Typical Vertical Flowline Connector

4.2.2.4 Tag Line Pull-In System This method relies on a pull-in line that is brought to the surface. Reaving of the line may be prearranged prior to initial deployment of the subsea manifold. An ROV connects one end to the flowline and the other end is connected to a line from the surface. By pulling on the surface line the flowline may be pulled into position. The flowline connection may be as described for the ROV pull-in system. Obviously the main limitation of this technique is its sensitivity to the motions of the surface vessel. It is best limited to benign areas and relatively modest water depths.



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4.3

Installation and Workover Riser Systems

4.3.1

INTRODUCTION

An installation and workover riser, sometimes referred to as a “landing string” is used primarily for running subsea tubing hangers, running subsea trees, pressure contained access to the well bore, and for temporarily flowing the well to the drilling platform. The primary functions of an installation and workover riser and associated equipment are to provide a means of lowering and setting subsea tubing hangers and/or trees and then to provide a pressure conduit into the well bore while simultaneously facilitating acceptable well control operations and disconnect possibilities during inert and live well flowing conditions. There are different designs of installation and workover riser systems for different types of subsea trees and for different sized subsea trees.

Figure 4.30 - Dual Bore Riser in a Typical Riser Shipping Basket

4.3.2

Riser System Design

The design of a riser system requires investigation of a complex interaction of the following variables: • • • • • • • •

Pressure rating – the riser must be able to contain well shut in pressure Bore size – wireline or coiled tubing equipment that will be used in the well must be able to pass through the riser, additionally the well fluid flow regime will be dictated by the bore Structural strength – the riser shouldn’t fail when being handled, or with applied tensions and bending moments Fatigue life – the riser must have a reasonable fatigue life – particularly if being utilized for a number of wells and for the life of a field. Practical operating limitations for the riser – driven by factors including allowable operating envelopes to prevent over stressing the riser, handling and make up time on the drilling rig, and physical size and weight limitations. Water Depth – affects loading on the riser Sea States - affects loading on the riser Current - affects loading on the riser



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• • •


Vessel Characteristics - affects loading on the riser Vessel Offset - affects loading on the riser Rig Handling and Deployment

There are two basic operating scenarios for an Installation and Workover Riser. These are 1) Deployment within a Drilling Riser and 2) Deployment in open water. Deployment within a drilling riser can be considered to be less severe service than deployment in open water in that the workover riser is shrouded within the drilling riser, but the variables noted above affect the performance characteristics of the riser in both scenarios as discussed below. As the water depth increases, the bending loads on the riser reduce, but the tensile loads increase. In shallow water, the problems are associated with the limitations to the operating envelopes for the vessel. Very small offsets can produce high bending loads in shallow water. The vessel’s motion characteristics in response to the Sea State also have a greater significance on the loading and a greater influence on the fatigue life in shallow water. In deeper water, the Sea States and vessel characteristics tend to have less influence and fatigue life improves. However, high currents can produce increased bending loading on a riser. This can lead to a lower fatigue life and a reduction in the operating envelope. When designing for deeper water, the wall thickness of the riser tubular may need to be increased in order to withstand the increased tensile loading, resulting in an increased stiffness. As the stiffness of the riser increases, the bending loads become greater and this again reduces the fatigue life. Sea States provide the forcing functions that are applied to the vessel. The vessel characteristics determine the vessel’s response to these forces that result in the vessel motions. These motions are more significant to the riser in shallower water than deeper water and in combination with vessel offset influence the allowable operating envelope for both riser strength and fatigue life. Sea currents have significant effects in deeper water. They can not be neglected in shallow either. The currents can vary with depth, magnitude, and direction. The larger the diameter of the riser, the greater the loading. In deep water, these loadings can create significant bending loads and fluctuating currents can result in greater fatigue loading despite depth. These are more significant in shallower water. Vessel Characteristics under varying sea states influence the loadings on the top of the riser. These effect fatigue life more than loading. Vessel Offset, the horizontal distance that the vessel is away from being vertically over the well, has a direct influence on the bending loads on the riser. To design a large bore workover riser for a multiple field role, a reasonably open operating envelope, a long fatigue life, shallow to deep water flexibility, under all conditions is probably impossible. It is therefore preferable to define all these variables prior to initiating the riser system design. The resultant design would be specific to a fixed set of conditions, but could then be analyzed for any variations in the conditions. The specific limitations, usually in the form of operating envelopes, need to be addressed for each set of field conditions. In some cases, this will result in a reduced operating envelope or maybe even a reduction of the full pressure rating. Historically, land based and then platform surface trees were concentric mono bore trees. The production bore rose concentrically through the casing and passed vertically through a stack of flanged individual gate valves. The tubing tended to be of smaller diameter and the pressures lower. Initially, subsea trees were surface trees with their materials and coatings selected for submersed operations. The annulus was spurred off horizontally, low down on the tree. The concepts of multiple completions down one well and Through Flow Line (TFL) techniques required a tube to pass vertically through the tubing hanger and down into the Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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annular cavity around the production tubing. Wire line plugs and tooling were required to enter this tubing for down hole operations and the riser had to provide the access. This was the Dual Bore Riser. In a dual bore system, and after the tubing hanger has been set, the annulus and production bores are sealed by setting a wire line plug in each bore at the tubing hanger. This will then allow the BOP to be retrieved with a barrier in the wellhead. The tree is then run and landed on the wellhead and tubing hanger. The two plugs are then retrieved through the dual bore riser. The annulus traditionally became a 2” bore - not for the three barrels per minute required for circulation, but because the smaller plugs had less reliable setting mechanisms. Current dual bore annulus tubing, still has 2 to 2 ½ “ diameter bores. Structurally dual bore risers generally rely on the strength of the production riser pipe with the annulus pipe hung between its connections. At these connections, the annulus pipe has telescopic joints - these avoid pressure, temperature and bending loads producing coupling forces at the connections. The connection tends to be of similar diameter to the tubing hanger. The production tubing is attached eccentrically by threading or welding and the annulus pipe is fed through another eccentric and diametrically opposed hole. The

Figure 4.31 - Tree Being Deployed on Dual Bore Riser connections are proprietary and often not suited to the vessel’s casing handing equipment. The demand for larger bores and higher pressures has pushed these pipes closer together. In many instances, the larger pipe and the need for vertical access to the down hole production tubing has forced the annulus to ‘dog leg’ through the tubing hanger body preventing down hole plug access. These twin bores passing through the major forgings for the tubing hanger, tree, lower riser package, and surface flow head are also reaching a limit. For sour gas applications, the forging material is either required to have a low hardness and therefore yield strength or utilize expensive and difficult to machine alloys. The low yield strength eventually restricts the differential pressure capacity. Yields are reduced further by high temperature applications. Connectors requiring welding of the tubular members also reach their limitations with restrictions on post weld hardness and the difficulty of welding higher yield materials. Higher yield pipe reduces the wall thickness and therefore the suspended weight of the riser. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The weight and costs of two pipes rather than one can become limiting as depths increase. Dual bore risers are used on about 50% of the trees in the world today. Horizontal trees, which do not utilize dual bore risers, make up the vast majority of the remainder of riser utilization. Horizontal trees use a mono-bore riser made from premium threaded tubing and readily rented riser valve and disconnect equipment and. Other riser types that have been deployed but in very limited numbers include a 1) mono-bore riser with a selector or diverter mechanism, or 2) a concentric riser system or a 3) mono-bore riser system with a mono-bore tree.

Figure 4.32 - A Subsea Tree Being Deployed With An Installation And Workover Riser



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4.3.3


Interface Considerations

A number of riser system interfaces that need to be considered whenever planning to deploy a rig and subsea system for installation or workover work on a subsea well include the following. • • • • • • • • • • • • • • • • • • • • 4.3.4

Vessel Response Amplitude (RAO) Met-ocean Design Criteria Rotary Table Vee Door Size Rig Floor Facilities / Geometry The BOP and component elevations Effective Derrick Height Coil Tubing Equipment Drilling Riser System Pipe Handling Facilities Wire line Equipment Riser Tensioning System Maximum Hook Load Riser Storage Capability Subsea Production Tree Control System Requirements Subsea Intervention System Tubing Hanger Running Tool Coil Tubing Lubricator Coil Tubing Lift Frame Types of Installation and Workover Riser Systems

The primary Installation and Workover riser configurations are: •

Conventional dual bore riser for operations carried out within a drilling riser while it is attached to an 18 ¾” wellhead and installing a dual bore tubing hanger. • Conventional dual bore riser for intervention operations carried out in open water while attached to a conventional dual bore tree. • Mono-bore riser for operations carried out within a drilling riser while it is attached to a horizontal tree and installing a mono-bore tubing hanger. • Mono-bore riser with a diverter or selector mechanism for use with a conventional dual bore tree system • Mono-bore riser for use with a mono-bore dual bore tree system – annulus access normally provided by hose in these systems and can thus be limited by water depth, pressure and hose cost or availability constraints. Simple drill pipe or tubing configurations for basic functions are also deployed for running basic systems or simple elements such as debris caps and are not discussed here as an installation and workover riser configuration. A brief discussion of these configurations is included in the following pages. Generally the descriptions of the riser systems and its major components start at the wellhead and move up the riser to the surface. Many of the principles for deployment and reasons for employment of different riser systems elements are shared between the different systems described. Obviously the design details may not remain constant between the various systems but will share common principles. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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4.3.4.1 Dual Bore Conventional Riser System Dual bore conventional risers are so named because they have two bores which enable wireline tool access into both the annulus and production bores and because this is the traditional configuration for subsea trees until the advent of the horizontal tree design. Subsea Christmas trees were originally designed so that the production tubing and tubing hanger would be installed in the wellhead through a subsea BOP stack and the tree later landed on top of the wellhead. Access to the two bores is required in order to be able to plug the bores off with wireline set plugs to mechanically isolate the well. This isolation would in turn enable the removal of the subsea BOP which in turn would allow the installation of the subsea tree which mates with the tubing hanger. Thus conventional dual bore trees are generally run on dual string risers, after the tubing hanger has been run and set. The same riser reconfigured in a different manner is used for tubing hanger and then tree deployment. This classically requires the tubing hanger to be orientated and locked down before retrieving the BOP stack and running the tree so that tree stabs that interface with the hanger correctly match up when the tree is run. As mentioned, the tubing hanger is run through the marine drilling riser and BOP stack before the tree is run. The tubing hanger is generally orientated with respect to the BOP stack, which in turn is orientated to the guide base on the wellhead. This can be done with a hydraulically actuated orientation pin added to the BOP stack, or with a preinstalled slot in the BOP hydraulic connector. The tubing hanger running tool interfaces with one of these orientation devices thereby orienting the tubing hanger with respect to the BOP stack. The BOP stack is orientated with respect to the guide base. Refer to the accompanying figures. Dual bore risers are normally specially built for each conventional specific tree size and type.

Figure 4.33 - Dual Bore Subsea Tree Being Deployed With LMRP And EDP Visible Above The Tree Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Figure 4.44 - Typical Dual Bore Conventional Riser System With Associated Tools, Adapters, And Accessories The diagram shows only one riser joint (below the tension joint). The majority of the riser length in the field is made up of several of the standard riser joints. Various shorter length standard riser pup joints may be used to adjust to overall make up length – particularly if the riser is used for several different wells. Note that the subsea tree and tubing hanger are not shown.



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Figure 4.45 - Dual Bore Riser Configured With Orientation Helix (Rotated 90 Degrees In View On The Right). The Tubing Hanger Running Tool Is Shown With The Riser On Right – Omitted On The Left.



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Figure 4.46 - A Dual Bore Riser System Configured To Run A Subsea Tubing Hanger Inside A Subsea BOP And Marine Riser



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Figure 4.47 - Dual Bore Riser System (See Previous Diagram) After Retrieval of the Subsea BOP and Marine Riser, Ready to Run the Subsea Tree Onto the Preinstalled Tubing Hanger Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The guide base is a common interface with the tree and therefore the tree can be orientated to a known tubing hanger orientation. There are numerous types of guide bases such as guidelineless, retrievable, and flow bases. If used a tubing hanger adapter spool may have its own guidance for the tree instead of relying on the guide base. Whichever design is employed, they will all share a means of orientation with respect to a common interface between the BOP stack and tree to enable orientation of the dual bore hanger and tree. It is very common for a reference slot on the 30 inch wellhead housing to determine the orientation of the guide base or tubing hanger adapter spool.

Figure 4.48 - Typical Dual Bore Riser Configured With An Orientation Joint Ready To Run A Tubing Hanger. Note The Helix Clearly Visible At The Lower End Of The Riser And The Dual Pipe Above The Slick Joint. If a tubing hanger adapter spool is used, another means of orientation includes a helix orientation shoe inside the tubing hanger adapter spool. A tubing hanger adapter spool is a piece of equipment that can be optionally placed on the subsea wellhead to provide a new Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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tubing hanger landing profile instead of the wellhead. The adapter can also be used to convert from one wellhead profile to another. Some concentric tubing hangers do not require orientation but this is generally with some compromise in the hanger capability or reliance on remotely operated annulus sleeve or other mechanism. Hanger capabilities that can be compromised are such things as electrical penetrations for gauges or other equipment. Dual bore risers are typically specially built for individual tree designs and can represent significant investment. Consequently, operators may try to use a single riser design across a variety of projects, which can impose restrictions on tree design or selection options. This can also have the disadvantage of leading to equipment availability conflicts if more than one field requires work at the same time while a restricted number of riser systems are available. Dual bore risers have historically not been generally readily available on the market for rent. This may traditionally have been due to the fact that there are many different dual bore tree

THRT Dual Bore Riser

BOP Slick Joint

Helix Muleshoe

Figure 4.49 - Dual Bore Tubing Hanger Orientation Joint With “Slick Joint” Clearly Visible – Shown Being Lifted From It’s Shipping Basket To The Rig Floor designs with variables such as pressure, bore sizes, bore spacings, and water depths different on different projects. Consequently large numbers of varieties of riser systems are required to accommodate all tree designs and equipment suppliers were not prepared to invest and have money tied up in varieties of riser systems. The Tubing Hanger Orientation Adapter can also be referred to as the "Tubing Hanger Orientation/Extension Joint." An acronym for this item of equipment is "THOJ". As described above, the lower section of the THOJ will include an orienting sleeve configured with a helix leading longitudinal slot. The tubing hanger orientation/extension joint includes two sections of flow pipe for the production bore and the annulus bore. The lower end of the THOJ includes stab subs to connect the THOJ production and annulus bores to the tubing hanger. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The middle section of the THOJ is smooth and has a reduced ID to allow both annular preventers of a typical subsea BOP stack to close for well control and for pressure testing of the tubing hanger seal. This area of the riser is often referred to as the “slick joint”. The lower end of the THOJ will normally include hydraulic stabs and sometimes electrical connectors that interface with the tubing hanger running tool. Umbilical clamps are located near the riser connections including at the top of the THOJ. The clamps secure the umbilical lines to the top of the THOJ. Hydraulic functions pass through the THOJ. This allows the BOP rams or annular bags to be closed on the joint and external pressure to be applied to the joint without affecting the hydraulic functions passing through it. When the tubing hanger is tagged out during installation, a hydraulically actuated BOP orientation pin mounted through the BOP makes contact with the THOJ and engages the slot on the orienting sleeve. As the THOJ is raised, the BOP orientation pin contacts the edge of the orienting helix and forces the THOJ to rotate until the pin engages the longitudinal slot. While landing the tubing hanger, the pin remains engaged in the slot to ensure proper orientation of the tubing hanger. Note that the hydraulically actuated orientation pin is not

Figure 4.50 - How The Orientation Helix Interfaces With The Orientation Pin Installed On The BOP normally standard on BOP stacks and has to be purposely installed for subsea installation and workover work. Note additionally, that various rigs have a huge variety of different BOP designs and stack up configurations. This means that the orientation system must be individually tailored to each rig. Consequently, the orientation system that may have been used to install a subsea tree system will more than likely have to be reconfigured to work the well over if a different rig is used for the workover. After the tubing hanger has been run, orientated and set or locked down, wireline plugs are set in the two bores and the riser retrieved to surface. The BOP stack is then retrieved to surface. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The riser is then reconfigured to deploy the subsea tree. This reconfiguration starts at the bottom of the riser where a Lower Marine Riser Package (LMRP) and Emergency Disconnect Package (EDP) are installed. The logistics of how and when this is done will depend on particular rig operating designs and procedures but generally, the subsea tree is prepared in the moon pool and the LMRP and EDP are stacked on top of it to be connected to the riser. When any type of pipe or riser are being run from a drill rig, some means of supporting the weight of the pipe must be provided. When drilling, rigs are equipped and set up to handle pipe at the rotary table through the use of “slips”. These are friction devices that are easily and quickly set and removed each time a connection is made at the pipe. Rotary tables and slips are designed for single round pipe. Dual bore risers have two sets of pipe and therefore cannot be hung off at the rotary table with conventional slips. The method that is used to run dual bore riser is to employ a device often referred to as a spider. Riser Spider The primary function of the Riser Spider is to provide a means to support the weight of the entire Riser or Landing String at the rotary table and thus relieve the hang-off weight from the travelling block. This allows the elevator to be unlatched in order to pick up another riser joint. The elevator is then available for handling joints as required, during the running and retrieving operations. For a dual bore riser, the spider enables slips to be set to hang off two strings. For all riser types, it also provides an opening for umbilicals, DHSV control tubing, and/or downhole gauge line(s) to exit from the rotary table master bushing to the rig floor. The Spider’s last function can often be to provide guidance to the Surface Joint as it strokes through the rotary with the vessels’ heave, after the Tubing Hanger has been landed.



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Figure 4.51 - Example Of A Spider For Running Installation And Workover Riser.



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Figure 4.52 - Dual Bore Riser Being Made Up At The Drill Floor. Note Use Of Dedicated Spider For Supporting The Already Suspended Riser.



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Figure 4.53 - Example Of A Spider Used To Run Dual Bore Risers

Figure 4.54 - This Drawing Shows A Typical Spider Design



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Lower Marine Riser Package (LMRP) The Lower Marine Riser Package (LMRP) plays a major role in emergency shutdown (ESD) operations as dictated by the rig well test or other control logic system. Additionally, the LMRP provides unrestricted access for wireline tools and coiled tubing when the LMRP, tree, and tubing hanger are connected together. The LMRP shuts the well in at the tree and is almost always designed to be capable of cutting wireline or coiled tubing in the event that they are in the well when the shut is required. The LMRP, when shut in, will allow a safe disconnect of the riser and therefore the rig from the subsea tree and well even if the well is live.

Figure 4.55 - Typical Lower Marine Riser Package (LMRP) and Emergency Disconnect Package (EDP) On Its Test Stand. All pressure containing components must have the same rating as the tree. A lower riser package (LMRP) usually includes three major components: • Valve block or Ram assembly with LMRP connector and Re-entry mandrel • Frame • Control System The LMRP valve block assembly can be described as consisting of three portions: upper, center, and lower. The upper portion of the valve block assembly includes a re-entry hub. The Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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re-entry hub includes production and annulus bore seal pockets that mate with the EDP Assembly as well as seal pockets that inter-face with the seals on the EDP stab subs. The OD profile of the hub mates with the EDP Assembly. The re-entry hub is part of the riser system that enables disconnect and reconnect and is designed with seals that make up remotely. A hydraulic stab plate is usually set at the re-entry hub. It contains hydraulic couplers that provide communication to the LMRP functions and to selected tree functions. It allows the installation workover control (IWOC) umbilical to be disconnected without damage if required with the EDP. The center portion of the valve block assembly is usually a composite valve block and may Upper

Alignment Pin

Upper Mandrel Mandrel Connection

Guide Post Top

Control Stab Plate

Hydraulic Coupler

Annulus Swab Valve

Guide Frame Cross Over Valve Production Swab Valve

Annulus Master Valve

Production Master Valve

Accumulator

Accumulator Lower Mandrel

Annulus Seal Sub Production Seal Sub

Connector

Stab Plate Hydraulic Coupler

Locking Segment

Primary Piston

Alignment Hole

Secondary Unlock Piston

Figure 4.56 - A Basic Lower Marine Riser Package (LMRP)

contain small BOP rams or valves corresponding to the bore sizes in the tree and riser. The block houses production and annulus valves or BOP rams or both. The valves or BOP rams on the production and annulus bores are normally fail safe-close design with a facility to shear. That is to say, if hydraulic power to the tree is lost, by for example umbilical damage, the valves or rams will close automatically, and will shear wire if in the well. Often a crossover valve is an integral part of the valve block assembly and provides communication between the production and annulus bores. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Methanol injection valves are often included in or on the valve block. Communication is achieved by direct porting into the production bore. The lower portion of the valve block assembly is a hydraulic connector that locks to the subsea tree mandrel. The connector is designed for remote operation and often has facility for both primary and secondary hydraulic unlocking. It will also have visual indicators that enables an ROV, or other conveyed camera, or diver to ascertain the status of all relevant, remotely operated functions for the connector. A second, lower LMRP stab plate fits onto the connector. It provides hydraulic communication with the tree upper stab plate. Certain couplers connect to valves that can vent fluid pressure upon disconnect. All others are able to seal to prevent ingress of seawater upon disconnect. Many tree systems are designed so that the installation and workover riser system and the hydraulic couplers contained in it disable the host production platform controls of the tree. The same mating halves of the described couplers on the tree are required to mate with the tree cap and its associated couplers before the production facility can take control of the tree. The lower end of the valve block at the subsea tree interface includes production and annulus bore, stab subs that seal in the tree upper seal pockets. The LMRP frame is a protective structure with bumper bars for protection of exposed equipment and guidance. Landing alignment posts on the LMRP frame provide primary guidance for orientation of the EDP/LMRP to the tree. The LMRP runs at the bottom end of the workover/completion riser string with the emergency disconnect package (EDP) latched to its upper mandrel profile. The assembled unit is then run on the dual bore riser system. The LMRP lands and locks to the tree upper mandrel profile. The workover umbilical, which mates with a stab plate on the EDP/LMRP assembly, provides communication from the workover control panel to selected tree functions. Emergency Disconnect Package (EDP) The Emergency Disconnect Package (EDP) provides the means for rapidly disconnecting from the lower riser package (LMRP) during completion or workover operations. The top of the EDP consists of a connector which mates with the pin on the lower end of the stress joint at the bottom of the riser. The base of the EDP consists of a hydraulic connector, which engages with the re-entry (upper) mandrel on the LMRP. The EDP is run latched to the re-entry mandrel of the LMRP. EDP assemblies are designed to be capable of being unlocked with the riser being pulled over at angles of 5 or more degrees from vertical. The connector will normally be designed to allow high angle release but sometimes, lift-off cylinders or jacks, which are activated after the EDP has been unlocked, are employed to lift the EDP connector up to make high angles of release possible. Seal subs provide communication in both the production and annulus bores. The bores have a pressure rating equal to the tree and provide unrestricted access for wireline tools and coiled tubing. A hydraulic stab plate which mates with a corresponding plate mounted to the frame of the EDP is usually employed to terminate the installation and workover umbilical. Hydraulic communication to the EDP, LMRP, and tree functions are typically routed through a stab plate mounted on the EDP frame. A hydraulic stab plate containing female hydraulic couplers is fitted to the body. This plate engages with a corresponding plate on the LMRP to establish communication. The EDP will normally also include a frame which acts as a protective structure and provides guidance for remote make up to the LMRP subsea tree during running.



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Stress Joint A Tapered Stress Joint or stepped stress joint is included in almost all installation and workover riser designs. It engages with the emergency disconnect package (EDP) and accommodates the larger loads that occur at the bottom of the dual bore completion riser system. It is called tapered because the wall thickness of the joint tapers from very thick at the bottom to thinner at the top – thus distributing stress more evenly through the joint than a straight pipe would. Alternative designs use a series of steps to provide the transition from thick wall at the base to thinner at the top. This is done because it is cheaper to manufacture and is almost but not as good as a true taper. It is important to note that the design of an installation and workover riser system and the stress joint in particular, is based on analyses that take into account the characteristics for a specific range of drilling rigs and the operating conditions under which it is anticipated to operate.

Radial Bolt Top Connection Radial Bolt Connector Locking Dog

Umbilical Connector Plate

Annulus Seal Sub and Seals

Production Seal Sub and Seals

Guide Frame

Connect or Primary Actuating Piston

Lift Off Accumulator

Connector

Stab Plate

Alignment Hole Hydraulic Coupler

Emergency Liftoff Cylinder

Connector Secondary Unlock Piston Locking Segment

Figure 4.57 - A Basic Emergency Disconnect Package (EDP)



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Standard Riser Joints Standard Riser Joints make up the largest length of the dual bore workover/completion riser system. They are used to run the EDP/LMRP and tubing hanger running/orientation joint. The riser joints have a dual bore design. One bore is the production line, which is normally the main load-carrying member. The second bore is the annulus line. It provides communication to the annulus bore but typically does not support any of the riser loads. It typically does not have connectors that restrain the pressure end load. Instead it is fixed to the production pipe with clamps that hold the pipe rigidly. The riser joints are typically compatible with all other joints in the system. The joints are normally fitted with clamps, which can accommodate the tubing hanger running tool or installation and workover umbilical(s). The joints will be designed to land out securely in manual and hydraulic riser spiders for running purposes. Riser Box Connection Annulus Bore

Retainer Ring

Annulus Bore

Alignment Key Slot

Riser Box Connection Production Bore

Retainer Ring

Riser Clamp

Production Bore

Alignment Ring Retainer Ring

Riser Pin Connection Annulus Bore

Riser Pin Connection Production Bore

Figure 4.58 - Typical Dual Bore Riser Standard Joint In addition to standard riser joints usually about 40- 45 feet long, there are typically 20 feet, 10 feet, and 5 fee. pup joints. These pup joints allow for optimization of space-out. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Tension Joint A tension joint assembly is positioned near the top of the riser below the drill floor. It is used to attach motion compensated tensioning cables. The tension joint is a dedicated joint that provides a means of tensioning the dual bore riser system during completion and workover operations. It is generally equipped with tension line connection eyes fitted to an independently rotating ring. The ring allows rotation without affecting the riser system. The tension joint is compatible with all other joints in the riser system. It should be sized to be run though the 37-1/2" diameter hole in the rotary table after removal of the riser spider assembly.

Figure 4.59 - Riser Tension Joint In Service In The Moon Pool



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Riser Box Connection Annulus Bore

Retainer Nut

Rotating Tension Line Connection Ring

Riser Box Connection Production Bore Alignment Plate Retainer Nut Production Bore

Tension Line Connection Eye

Annulus Bore

Riser Clamp

Alignment Ring Retainer Riser Pin Connection Annulus Bore

Riser Pin Connection Production Bore

Figure 4.60 - Conventional Dual Bore Installation and Workover Riser Tensioner Joint



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Surface Tree or Surface Flow Head A Surface Tree is always run at the top of the riser often just above an optional surface protection joint on the dual bore completion riser system. The surface tree is the primary control for the well during normal well testing or clean up operations. The optional surface protection joint protects the production line, annulus line, and the tubing hanger running tool umbilical from damage at the point where the riser passes through the rotary table. Valves fitted in both the production and annulus bores provide a shear/shut-in mechanism during completion and workover operations. Both valves are normally capable of shearing braided cable or slickline. The surface tree provides an upper flow control barrier for the riser. Its wing valves direct production flow to the choke manifold and well test equipment on the rig. Generally, a swab valve allows vertical access into the riser bore for wire line or coiled tube deployed tools.

Figure 4.61 - A Photo Of A Simple Surface Tree (Or Flowhead) For A Dual Bore Riser System –Shown On Its Side. The riser weight is suspended from the surface tree that is in turn suspended from the crown block. A swivel is generally installed beneath the tree to enable the tree to be rotated to assist with the line up of the choke and kill lines above the drill floor. In a horizontal tree system, the swivel also allows the tubing hanger to orientate when landing, or the tree to orientate in a dual bore tree system. The swivel also eases the make up of the last riser connection, if the connection is threaded or requires orientation. The surface tree must also be elevated above the deck to accommodate vessel vertical movement. One of the limiting features of the surface tree is its overall stack-up height when combined with the Swivel, the Surface Joint and a Coiled Tubing Tension Frame inside the derrick. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Typically an elevator profile is machined below the upper connection on the surface tree to enable the tree and riser to be supported by the draw-works. A working platform is often mounted around the surface tree to enable personnel to operate manual valves and work the connection of the lubricator unit. Lubricator adapters at the top of the tree block assembly enable the attachment of wireline or coiled tubing lubricators which in turn allow tool access to a live well bore. The production lubricator adapter is normally shouldered to be compatible with elevators for handling purposes. Wing valves are fitted to outlets on the production and annulus bores and are typically

Figure 4-62: Example Of A Simple Surface Tree (Or Flowhead) For Dual Bore Riser System. Note Only One Master Valve In The Annulus And Production Strings. Many Systems Contain Additional SWAB Valves Above Master Valves. hydraulically actuated so that they will shut in automatically when tripped by the rig well test ESD.

A large (e.g. twenty-inch) casing elevator profile on the block allows the tree to be suspended by a tension frame assembly – see description below. The derrick system applies motion compensated tension to the installation riser. The load path could pass down bails hung from the travelling block, through an elevator to the surface flow tree and on down to the riser. However, this method restricts coiled tube and wire line access to the top of the tree. To obtain this access a tension frame is used above the surface tree. A coiled tubing gooseneck, injector head, and the lubricator can then be installed within Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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the frame if required. It can take 24 hours rig time to change from the bails system to the tension frame and operators install the frame as a safety precaution.

Figure 4.63 - A Variable Length Tension Frame. It is suspended from the travelling block in the derrick and it in turn suspends the surface tree (shown) and riser (not shown). It provides room above the surface tree for wireline lubricators (not shown) and enables the easy placement of a coiled tubing or snubbing unit if required.



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A surface tree is run at the top of the riser in the same manner and for the same reasons as in the dual bore riser system.

Figure 4-64: Surface Tree In The Derrick – Note The Man On The Sling At The Wireline BOP To Install The Lubricator Above The Surface Tree.



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4.3.4.2 Horizontal Tree Riser System Horizontal trees are generally run on drill pipe with a tree running tool at the bottom of this “drill pipe riser”. The drill pipe riser and tree running tool are then retrieved. Unlike the riser system for a conventional dual bore tree described above, the tubing hanger is not run before the tree in a horizontal tree system and thus only one pressure containment riser is deployed. The marine drilling riser which is part of the BOP system on the drilling rig is then used to deploy the BOP stack and become the environmental riser for access into the well through the tree, primarily for drilling and completion tubing deployment. Recall that the pressure rating of the marine drilling riser is typically very low –around 500 psi– and is almost certainly expected to be rated less than the well shut in pressure. The BOP rams or annular bags are utilized to isolate the marine riser from the well pressure if there is any form of kick during any of these preliminary horizontal tree operations by closing them. Finally, when the tubing hanger is landed in the horizontal tree, it is done with the installation riser inside the marine-drilling riser. This riser is often referred to as the “landing string” because it is used to land the completion and tubing hanger. The riser is designed so that the BOP rams are closed on the riser during well operations once the riser is installed. This

M arin e R iser

F lo w H ead (not sh ow n)

L u bricato r V alve Sh e ar S u b

BOP S tack 9 -5 /8 r a m s

R etain er V alv e

T u b in g H a n g er

S u bsea T ree

S u bsea T est T ree S lick Jo in t

W ellh ead

T u bin g H ang er R un n in g T o ol T u bin g H ang er

Figure 4.65 - Typical Horizontal Tree Installation And Workover Riser System Deployed Inside A Subsea BOP Stack. ensures that the Marine drilling riser is not exposed to high pressures. The installation and workover riser for a horizontal tree normally consists of premium threaded tubing or casing and is additionally normally configured with a number of valves and disconnect mechanisms to safely handle a number of unplanned possible events that could Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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occur that may compromise safety. This is the riser of interest and discussed below. All the valves and bore sizes must be suitable to pass the wireline plugs required in the tree. These are normally larger than any other tools or device than must pass into the production tubing down hole and usually dictate the size of the riser or landing string. Test Tree The subsea test tree (SSTT) is deployed at the bottom of the installation and workover riser for a horizontal tree system. The SSTT is typically configured with two valves. The tree is hydraulically operated and requires an umbilical to be run with the riser system inside the marine drilling riser. They are normally fail safe close valves. The SSTT serves several functions.

Figure 4.66 - Subsea Test Tree With Disconnect Feature The primary function of the SSTT is to provide valves at the bottom of the riser to shut-in the well at the tree if desired because there are no valves in the vertical bore of the tree. The valves are designed to be capable of cutting wireline or coiled tubing if they were in the bore at the time of closure and to be capable of sealing after cutting. Another function of the tree is to allow the riser to be disconnected above the closed valves on the SSTT if desired. This feature is reversible and enables a remote reconnect if disconnection did take place. The SSTT connection system includes a hydraulic interface for all the hydraulic functions for the SSTT and the tubing hanger running tool. The reconnect feature is designed to be self-aligning and all stingers will only make up once the correct alignment is achieved. The SSTT also incorporates a slick joint, which allows the BOP rams to be closed on the riser system. This serve to prevent high pressure from entering the marine drilling riser and as a secondary hold down of the lower end of the riser. The slick joint is generally at the bottom of the SSTT. If the tubing hanger running tool is hydraulically functioned (for deep water, they Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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virtually all are), the slick joint will have porting through it for the tubing hanger functions. This allows hydraulic communication without hose or piping and thus prevents the rams or externally applied pressure from affecting the hydraulic functions. The slick joint is the interface between the SSTT and the tubing hanger running tool. Once the riser has been run, it can be tested against a closed valve in the SSTT for pressure integrity.

Coiled Tubing

Ball Valves

Figure 4.67 - Cut Away Section View Of Subsea Test Tree (SSTT) Used With Horizontal Tree Riser Systems



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Retainer Valve The retainer valve, or riser containment valve, is deployed low in the installation and workover riser, above the SSTT. The purpose for the riser containment valve is to prevent high pressure and/or hydrocarbons in the riser from being released into the marine drilling riser in the event of an emergency disconnect.

Figure 4.68 - Retainer or Riser Containment Valve The release of hydrocarbons into the marine drilling riser or open sea is problematic, but the uncontrolled release of riser pressure into the marine drilling riser could prove to be catastrophic. This could launch the riser up into the rig floor. It could burst the drilling riser. It could divert large quantities of hydrocarbons including gas to the drill floor, which could burn or explode. It could evacuate the drilling riser then allowing external hydrostatic pressure to collapse it. The retainer valve typically incorporates logic that does not allow a disconnect to occur until the valve is closed. The valve is hydraulically actuated. It is normally the termination point for the tubing hanger running tool and SSTT control umbilical(s). The hydraulic lines are typically ported through the body of the valve to the SSTT from the umbilical termination.



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Lubricator Valve The lubricator valve is an optional valve usually installed in the installation and workover riser just below the rotary table. It allows long tool strings to be deployed in the well without exceptionally long lubricators being deployed above the surface tree above the drill floor.

Figure 4.69 - Lubricator Valve or Well Re-entry Valve



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4.3.4.3 Other Installation And Workover Riser Systems Other tree types such as the “Thru-Bore” tree and mono-bore trees have utilized slightly different riser configurations from those described but they employ the same principles of well control issues and disconnect. The systems utilize hose access to the annulus for circulation and pressure relief functions. Hose can be restrictive in cost, through bore, availability, pressure rating, and depth tensions and so are not normally used in deep water.

Figure 4.70 - Example of a Mono-Bore Riser System



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4.3.5


Well Test and Clean-Up of Wells

Among other things, installation and workover risers are used to flow wells for test purposes and/or for clean-up of wells before turning the well over to production operations. This requires that the riser be connected to well test equipment on the rig, such as test maseparator. The well test equipment is used to handle the produced fluids. The well test equipment is not covered in the scope of this section

4.4

System Commissioning and Start-Up

The following are some items to consider when planning the commissioning and start-up of a subsea production system. • • • • • • • • • •

Conduct a full functional test of the production control system. Verify operation of all valves. Record operating time and valve actuation response signatures. Observe operation using ROV. Confirm choke actuation response. Observe with ROV. Calibrate choke position versus flowrate. Verify proper operation and calibration of downhole pressure or temperature transmitters. Establish threshold settings for acoustic sand monitoring sensors. Pressure test certain critical seals in field made-up connections. This may be done with the IWOC umbilical or ROV hot stab, depending on the design. Verify electrical umbilical continuity and insulation integrity. Flush and pressure test hydraulic and chemical umbilical hoses. Verify hydraulic and chemical umbilical communication. Conduct cold start procedures for the well. Even oil wells may have an initial charge of gas that can affect the start-up procedures. Procedures may involve specific valve opening sequences just for start-up, special choke settings, or methanol injection for hydrate prevention.



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5


FIELD ARCHITECTURE

5.1

Field Architecture Considerations

The purpose of the field development is to safely and efficiently recover the reservoir hydrocarbons, process them, deliver them to market and dispose of unwanted byproducts. This involves many considerations and, as is the case with most field developments, must usually be undertaken with less than the desired amount of information. The objective is to maximize the return on investment within a tolerable level of risk. The numbers of issues to be considered are many. The following is a summary of some important ones: •

Existing Infrastructure. Installation of new infrastructure in deep water is exceedingly expensive. The first thought when considering a new development should be to make use of existing infrastructure if possible. This includes existing production platforms, pipelines and even wells.

Figure 5.1 - Examples of Host Platforms Available For Tieback

• • • • •

Well groupings. Clustering wells or installing well templates can facilitate drilling operations and save flowline cost. Optimizing intrafield flowline configuration. Pigging requirements must be identified and addressed. Long tie-backs will dictate the use of electrohydraulic production controls. This may add some expense for a development of only a few wells. Possible need for subsea production boosting (pumping) as part of the initial development or future needs



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Figure 5.2 - One Example of a Subsea Pumping Module



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5.2


Well Grouping

Field development planners need to work closely with the reservoir and drilling engineers early in the planning stages to establish a good well location plan. Once the reservoir is mapped and reservoir models created the number of wells, types of wells and their locations can be optimized. Well layout is usually an exercise of balancing the need to space the wells out for good recovery of the reservoir fluids against the cost savings of grouping the wells in clusters. Add to this the consideration of using extended reach wells, and the number of possible variables to consider becomes great. A further consideration, reservoir conditions permitting, is the use of fewer, high production rate wells through horizontal well completions or other well technology. Here again, there are cost tradeoff considerations.

Single Well

Well Pair

3-Well Manifolded Cluster

Figure 5.3 - Three Types Of Well Grouping: Single Well (Satellite), Well Pair and Cluster



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5.2.1


Satellite Wells

A satellite well is an individual subsea well, usually supported in a single free standing 30” conductor. Satellite wells are typically used for small developments requiring few wells. Often the wells are widely separated and the production is delivered by a single flowline from each well to a centrally located subsea manifold or production platform. Various field layouts must be examined. This evaluation must involve hydraulic calculations and cost sensitivity analyses taking into consideration flowline cost, umbilical cost, installation cost and flow assurance issues.

5.2.2

Template and Clustered Well Developments

If subsea wells can be grouped closely together, the development cost will usually be less than for an equivalent number of widely dispersed wells. Well groupings may consist of satellite wells grouped in a cluster, or a well template, in which the well spacing is closely controlled by the template structure.

5.2.2.1 Clustered Satellite Wells Clustered satellite subsea well developments are less expensive than widely spaced satellite wells mainly because of flowline and control umbilical savings. If several satellite wells are in close proximity to one another, a separate production manifold may be placed near the wells to collect the production from all the wells and deliver it in a single production flowline to the production facility. Also, a single umbilical and UTA can be used between the well cluster

Host Facility Umbilical

Flowlines

UTA

Manifold

Flying Lead

Tree

Flowline Jumper Well Jumper

Figure 5.4 - Typical Well Cluster Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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and the production platform. Figure 5-4 shows a field with three clustered satellite wells, a subsea production manifold and a single production umbilical and UTA. In the case of clustered satellite wells, wells may be placed from several meters to tens of meters from one another. The wider well spacing is often dictated by a desire to be able to position the drilling rig over one well without imposing dropped object risk on adjacent wells. It is hard to precisely control the spacing of individual satellite wells, so crossover piping and control umbilicals must be able to accommodate the variations in spacing.

5.2.2.2 Production Well Templates Another way of clustering wells is by means of a well template. Well templates are structural weldments that are designed to closely position a group of well conductors. Well templates may support two wells or more than a dozen wells. Apart from reservoir considerations, the number of wells in a well template is only limited by the size of the well template that can be handled by the installation vessel. Small templates are usually deployed from the drilling rig. Larger ones may require a special installation vessel with heavier lift capacity or better handling characteristics. The following are some benefits of production well templates as compared to clustered satellite wells: • • • • • • •

Wells are precisely spaced. Manifold piping and valves can be incorporated. Piping and umbilical jumpers between the trees and manifolds may be pre-fabricated and tested prior to deployment offshore Piping and umbilical interfaces are less expensive than for clustered wells. Installation time is reduced by modularizing much of the equipment. Short flowline piping distances (compared to a cluster) reduce the problems associated with flow assurance (e.g. wax and hydrate formation) and the need for extensive pipe insulation. Horizontal loads imposed by drilling can be taken by the template structure as opposed to the tree and conductor in the case of a satellite well.

The following are some disadvantages of production well templates as compared to clustered satellite wells: • • • • • •

Design and fabrication time may be longer due to greater complexity. There may be safety concerns related to simultaneous drilling and production operations. Heavy templates may be more susceptible to subsurface instability, such as shallow water flows. Less flexibility in determining well locations. Fewer qualified contractors and suppliers. ROV access may be limited due to space constraints.



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5.3


Drilling and Well Intervention Considerations

Some of the drilling and well intervention issues that should be considered during subsea field development planning are : •

• • • •

•

5.4

Satellite well spacing may be dictated by a desire to be able to position the drilling rig over one well without imposing dropped object risk on adjacent wells, thus allowing production to safely continue through adjacent wells during drilling or workover operations. Production template size may be limited by the installation rig equipment handling capabilities. The same applies to manifolds and other equipment that may be installed by the rig during drilling or well completion operations. Satellite trees, production template, and manifold controls, junction plates and other control interfaces must be designed to accommodate the IWOC system to be used on the installation or workover rig. The ROV intervention system and ROV tools must be compatible with ROV and ROV handling equipment to be used on the installation or workover rig. BOP compatibility. The well completion equipment must be compatible with BOP equipment typically available in the area. The most common area of conflict is the BOP connector profile which can be addressed by using a compatible wellhead and tree connector, or changing the wellhead connector on the BOP. If an atypical size or pressure rating is to be accommodated, such as a 16-3/4” or 15M wellhead, a suitable BOP will have to be obtained. Well wireline or coiled tubing intervention from DSVs may become more commonplace.

Intrafield Flowlines

Intrafield flowlines are the network of pipelines between the individual wells, well templates, subsea manifolds, and production platforms. Intrafield flowline requirements will be established by the number of wells, well locations, well grouping and manifolding arrangements, well testing requirements, pigging requirements, gas lifting requirements, gas injection requirements, water injection requirements, operating pressures, production rates and shut-in pressures.

5.4.1

Flowline Routing

Each well has at least one production flowline that must be routed to a delivery point, usually a centrally located production facility or a manifold. The most efficient arrangement of wells, flowlines, manifold and production platform is usually the one that results in the fewest number of flowlines of the least combined length. Other factors may force developers to consider other flowline routings, however. These include the following: •

• •

Differences in reservoirs and well performance. Some wells are capable of flowing greater distances than others due to their higher pressure or lower pressure drop (such as a high gas-oil ratio well versus a low gas-oil ratio well). This might affect where the production facilities are located or how the flowlines are routed. Differences in flowline metallurgy (such as a well high in CO2 versus one that is low in CO2). Minimizing the length of the more expensive (alloy) flowline might result in net savings. Differences in pigging requirements. The platform might be best located nearer the wells requiring frequent pigging versus those that do not.



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• • • • • •

5.4.2


Providing clear areas or easements for future wells or flowlines. Avoiding interference with production platform moorings. The same applies to drilling rig moorings if anchored rigs are considered. Avoiding hazards such as debris, outcroppings, canyons, or geotechnically unstable areas. Avoiding existing pipelines or cables. The direction of approach to production platform, often dictated by the riser configuration. The type of well fluid. A water injection line may be cheaper than a production line.

Tie-Back Distance

For a large scale new field development involving the installation of new production facilities, the production platform is usually optimally located relative to the planned production wells. Many marginal fields are developed with subsea completions with subsea tie-back flowlines to existing production facilities some distance away. Subsea tie-backs are an ideal way to make use of existing infrastructure. Long tie-back distances impose limitations and technical considerations, however. The following are some of the main considerations: •

•

•

5.4.3

Reservoir pressure must be sufficient to provide a high enough production rate over a long enough period to make the development commercially viable. Gas wells offer more opportunity for long tie-backs than oil wells. Hydraulic studies must be conducted to find the optimum line size. Because of the long distance traveled, it may be difficult to conserve the heat of the production fluids and they may be expected to approach ambient seabed temperatures. Flow assurance issues of hydrate formation, asphaltene formation, paraffin formation and high viscosity must be addressed. Insulating the flowline and tree might not be enough. Other solutions can involve chemical treatment and heating. The gel strength of the cold production fluids might be too great to be overcome by the natural pressure of the well after a prolonged shutdown. It may be necessary to make provisions to circulate out the well fluids in the pipeline upon shutdown, or to push them back down the well with a high pressure pump on the production platform, using water or diesel fuel to displace the production fluids.

Commingling of Production

Commingling production is a good way to reduce the number of flowlines and save cost. Production from a group of individual wells may be commingled in a subsea production manifold situated near the wells. The commingled production may be delivered in a single flowline to the production facilities. When wells are commingled, the performance of the wells must be matched. Higher pressure wells must be individually choked so as to not impede the flow of weaker wells. If the expense can be justified, a HP and LP manifold can be provided with separate flowlines for each.



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5.4.4


Well Testing

Good reservoir management requires individual wells to be periodically flow tested to measure their individual performance and production fluid characteristics. For dry tree production, a well testing manifold and test separator are usually provided as part of the production facilities. The flow from each well may be individually diverted through the test header to the test separator. The same can be done in the case of subsea wells. For satellite wells with individual flowlines tied back to the production platform, it is often simply a matter of connecting the well flowlines to the well test manifold. A well test heater may be needed ahead of the separator that otherwise might not be necessary in the case of dry tree production. If the subsea production is coming from a subsea manifold, the subsea manifold could be provided with a well test header. This requires additional manifold valves for each tree, and a separate well test flowline to deliver the test well production to the test separator on the production platform. Sometimes, if only one flowline is available and several wells are producing into it, the wells may be “tested by difference”, that is one well is individually shut-in and the difference in the production rate of each phase of the remaining production is measured. This requires a test separator large enough to handle production from more than one well, or metering on the production separator. For long tiebacks it becomes very expensive to add a flowline and production platform riser just for well testing. That has led to the development of subsea multiphase flow meters. Multiphase flow meters are capable of measuring the oil water and gas phases separately. Their applicability is limited, but the technology continues to improve and when faced with no simple alternatives they are definitely worthy of consideration.

5.4.5

Pigging

Pigging of flowlines is often necessary to remove paraffin deposits, produced sand and other debris that may accumulate in the flowline. Pigging may be done on a regular basis as preventive maintenance, as a remedy to an unforeseen fouling problem, or as a diagnostic tool. Different types of pigs are available for different situations. Some impose limitations on the pipeline design and should be considered beforehand. The following are a number of issues that should be considered when planning a field development that will include provisions for pigging flowlines:

5.4.5.1 Pigging Loops (Round Trip Pigging) Because only one end of the pipeline is usually accessible from the production platform it is common to provide a looped path for the pig with the pig launcher and receiver on the same platform. The loop may be two pipelines parallel to one another with a pigging crossover valve at the far end from the production platform. The far end of the lines might be at a production manifold or an individual satellite subsea tree. Pigging operations require pushing the pig from the platform, through the crossover, and back again. A production well, pump, compressor, buy-back gas or other fluid pressure source must be available on the platform to displace the pig. Production operations might have to be curtailed, some wells shut-in or production re-routed during the pigging operations. The extra line required for pigging may have uses other than pigging. During normal operations both lines could be used to handle production fluids, or one line might be used for flow testing one well while the other handles production from other wells, or one could serve as a high pressure (HP) production line while the other serves as a low pressure (LP) production line. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Satellite wells, each with a separate flowline to the production platform, may be connected to one another to create a pigging loop. A pigging tee would be required on each tree and a pigging crossover valve on one or both trees.

5.4.5.2 Subsea Pig Launchers and Receivers Pigging loops become expensive for long tiebacks and pigging very long distances may be problematic due to the amounts of fluid involved, the time involved, or the pressure required to displace the accumulated wax and debris. If operating conditions allow, consideration might be given to using a subsea pig launcher and pigging from the subsea production manifold or tree to the production platform. The production fluids can be used to propel the pig. It may be necessary to regulate the production rate so as to control the pig speed. The optimum speed is usually 1-2 m/sec. Alternatively a subsea pig receiver may be installed at the far end of the pipeline and the pig driven from the platform to the receiver. Because of the problem of where to deliver the displaced fluid, this method is best reserved for pipeline de-watering, or other situations where displaced fluid disposal is not a problem. Sometimes a loop may be available but the pipeline sizes are incompatible. In such cases one-way pigging may be possible, by displacing the fluids from one section of the line into the other. Because of the need for subsea intervention for subsea pig launching and receiving, this is best approached as a contingency provision for service that would require only very infrequent pigging. It is possible that a loaded pig launcher could be pre-installed on a tree or manifold prior to initial deployment so that subsea intervention would not be required the first time. Subsea pig launchers and receivers have not found wide usage. They are typically unique, project-specific designs.



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5.5


Future Development, Expansion

Good field development planning requires making provisions for future development or expansion. Unfortunately, contingency provisions usually add cost, and it is often very difficult to foresee what the future development needs may be. The following are some future development planning ideas the subsea field development planners might consider: • • • • • • • • • • •

Allow space for future satellite wells, including rig access. Provide spare slots in templates for future wells. Allow space for future flowlines, or size flowlines to handle future capacity. Provide spare subsea manifold valves and flowline tie-in provisions. Provide space for future risers on the production platform, or pre-install risers. Design capacity for future wells into the production control system. Design capacity for future wells into the production control umbilicals. Allow space for future umbilicals. Provide interfaces for additional flying leads on subsea manifolds or subsea trees. Make provisions for future gas lift, such as pre-installing gas lift flowlines or configuring tree to accommodate a future gas lift tie-in. Plan for future gas injection wells or water flood wells taking into account all the issues raised above for production well

Figure 5.5 - Cluster Type field development.



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6


RISK ASSESSMENT AND MANAGEMENT

Risk may be defined as an unexpected or an undesired outcome of an action or series of actions. All human endeavors entail risk. In offshore field developments the risks that are of greatest concern are those that can negatively affect the health and safety of individuals, the environment, or the economics of the project.

6.1

Potential Areas of Risk

The following are potential areas of risk in a subsea development project.

6.1.1 • • • • • • •

6.1.2 • • • • • •

6.1.3 • • • • • •

Project Management Poor interface planning and management. Poor communications. Unrealistic schedules or budgets. Poor resource planning. Inadequate resources. Poorly trained personnel. Labour disputes. Failure to identify or anticipate regulatory requirements.

Engineering Inadequate or erroneous design information. Calculation errors. Drawing errors. Poor document control and engineering QA procedures. Inadequate risk or hazard assessment. Failure to anticipate and design for likely off-spec conditions.

Manufacturing Delay in receipt of materials. Defective materials. Manufacturing errors. Component failures during testing. Poor fit-up of components. Inadequate quality assurance procedures or implementation.



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6.1.4 • • • • • • •

6.1.5 • •


Installation Inadequate equipment. Poor interface planning. Installation equipment availability delays. Installation equipment failure. Installation errors or delays. Equipment or system failures during commissioning. Failure to anticipate and prepare for weather risks.

Operations Inadequate operator training. Unanticipated operating conditions.



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6.2


Risk Management

Operators and contractors should implement proactive risk management programs. Risk is a product of uncertainty. With the accumulation of relevant experience in the industry, risk can be mitigated. When entering a new area of development, extending the limits of current technology, or undertaking a new contractual commitment, new risks are introduced. Risk management should be applied early and continue through the project. Employees, contractor personnel, operators and other participants should be indoctrinated with an awareness of the risks faced by the project within their sphere of involvement, and the mitigation measures available to them. Adequate resources should be committed to the mitigation of risk and responsibilities formally assigned.

6.2.1

Risk Analysis In The Project Phases

6.2.1.1 Phase 1, Feasibility Study • Identify alternative concepts for screening. • Evaluate relative capital cost and operating costs for each concept. • Identify areas where technology development may be necessary. • Conduct a high-level comparative risk assessment of each concept 6.2.1.2 Phase 2, Concept Study The concept study focuses on the concept (or concepts) resulting from the feasibility study. The engineering is taken to a higher level of definition. • • •

Prepare conceptual drawings and bases of design. Conduct a high level hazard identification review. Identify areas of risk for further study.

6.2.1.3 Phase 3 – Preliminary Engineering The goal of preliminary engineering is to develop the design to the point that a detailed engineering contractor can carry it to completion. In preliminary engineering the basis of design is firmly established, the scope of work is clearly laid out, and specifications for all major systems and components are prepared. • • • •

Conduct a formal hazard identification review and identify areas of focus for further engineering to further mitigate risk. Conduct a formal hazard and operability review using the project basis of design and the preliminary drawings. Follow up the hazard reviews with a punch list of items to be addressed by further engineering. As these are addressed, revise drawings and other documents accordingly. Conduct a follow-up hazard review to assure that all punch list items have been addressed and no new issues introduced.



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6.2.1.4 Phase 4 Detailed Engineering • Track and document all changes to the preliminary design basis of drawings during detailed engineering. • Near completion of detailed engineering, conduct final hazard and operability reviews with most up to date drawings, addressing all new developments introduced during detailed engineering. 6.2.1.5 Phase 5, Construction • Review contractor’s qualifications and financial stability. • Review contractor quality plans and QA procedures. • Audit contractor performance. • Review contractor personnel qualifications. • Conduct safety evaluation of work procedures and emergency procedures.



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6.3


Lessons Learned

The following are some specific issues arising from “lessons learned” during previous subsea projects. • •

• • •

• • • • • • • • • • • • • • • • • • • •

Fluid incompatibility –particularly completion fluids mixed with control fluids or injection chemicals can result in formation of gels or precipitants, causing line blockage. Pressure differentials due to hydrostatic column heads of differing fluids. Example: riser full of completion brine and umbilical control line at same depth can result in unexpected pressure differences resulting in component failure or undesired fluid migration. Even light corrosion (rust) in chemical storage tanks can damage high-pressure chemical injection pumps. Significant corrosion has been experienced on subsea control pods that had been installed but not operated for some months. Hydraulic compensation system must accommodate ROV override before control system activation, otherwise seawater can be pulled into the SCM during override functions. Client imposed requirements have demanded that a vendor change standard product lines to use unsuitable grades of stainless steel. Catastrophic filter failure has contaminated clean control fluid. Cracks have occurred in the duplex stainless steel materials after deployment subsea. Overactive cathodic protection levels have caused hydrogen embrittlement in bolting and other steels. There is a need for better understanding of the factors inducing cracking in duplex stainless steel materials, when cathodically polarized in seawater. As with duplex stainless steel materials, there is potential for hydrogen embrittlement, when 13% Cr. is subjected to cathodic protection. Trees have been dropped due to operator error at hydraulic panel. Umbilical reels have shifted on deck – should be welded down. Poorly designed reels have injured people – projections on the reel catch body parts while rotating. Control handle should not be near moving parts. Thermoplastic umbilical hoses have the potential for hose collapse in deepwater, because during blow-down the internal pressure could be zero. A remedy can be control by operational procedures. Cleanliness with carbon steel umbilical tubes is difficult to maintain. Storage fluid in carbon steel tubes should be heavily inhibited. Hydraulic control equipment should be filled with inhibited control fluid. Hydrogen cracking has been reported in Monel 400 end fittings in the termination assembly. Dissimilar metals at pressure fittings must be closely evaluated. Example case is corrosion of copper washers in methanol hose connections caused by galvanic reaction with the Monel® 400 fittings. Titanium electrical connectors may need to be isolated from the cathodic protection system. Either coupler or both hydraulic couplers shall be allowed to float in the equipment it is mounted in to allow proper seal usage. Hydraulic coupler poppets and/or small tubing and tube fittings can cause blockage points in high flow and/or high trash lines like methanol and annulus vent lines. Salt crystals in the methanol hose and termination due to ingress of seawater. Stem seals on tree and manifold valves in some cases were not rated for the appropriate external pressures.



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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK SEALINES


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TABLE OF CONTENTS 1

2

INTRODUCTION ......................................................... ERREUR ! SIGNET NON DEFINI. 1.1

SCOPE ................................................................................... ERREUR ! SIGNET NON DEFINI.

1.2

REGULATIONS, CODES, STANDARDS & SPECIFICATIONS ......... ERREUR ! SIGNET NON DEFINI.

1.3

DEFINITIONS & ABBREVIATIONS .............................................. ERREUR ! SIGNET NON DEFINI.

1.4

REFERENCES ......................................................................... ERREUR ! SIGNET NON DEFINI.

1.5

ACKNOWLEDGEMENTS ............................................................ ERREUR ! SIGNET NON DEFINI.

PIPELINE DESIGN FOR DEEP WATER .................... ERREUR ! SIGNET NON DEFINI. 2.1

INTRODUCTION ....................................................................... ERREUR ! SIGNET NON DEFINI.

2.2

MATERIAL SELECTION ............................................................. ERREUR ! SIGNET NON DEFINI.

2.3

PIPELINE DESIGN METHOD....................................................... ERREUR ! SIGNET NON DEFINI.

2.3.1. General consideration........................................................ Erreur ! Signet non défini. 2.3.2. Pipeline diameter determination. ....................................... Erreur ! Signet non défini. 2.3.3. Pipeline wall thickness....................................................... Erreur ! Signet non défini. 2.3.4. Dynamic calculations. ........................................................ Erreur ! Signet non défini. 2.3.5. Stability check. ................................................................... Erreur ! Signet non défini. 2.3.6. Span calculations............................................................... Erreur ! Signet non défini. 2.3.7. Pipe expansion calculations. ............................................. Erreur ! Signet non défini. 2.3.8. Upheaval buckling.............................................................. Erreur ! Signet non défini. 2.4

DESIGN BASED ON LOCAL BUCKLING CRITERIA VERSUS BUCKLING PROPAGATION CRITERIA ERREUR ! SIGNET NON DEFINI.

2.5

RADICAL ALTERNATIVE APPROACH IN DEEPWATER PIPELINE LAY ........ ERREUR ! SIGNET NON

DEFINI.

3

4

INTERFACE REQUIREMENT..................................... ERREUR ! SIGNET NON DEFINI. 3.1


3.2

PIPELINE END TERMINATIONS .................................................. ERREUR ! SIGNET NON DEFINI.

3.3

SUBSEA PRODUCTION SYSTEM ................................................ ERREUR ! SIGNET NON DEFINI.

3.4

INSTALLATION VESSELS........................................................... ERREUR ! SIGNET NON DEFINI.

SEALINE TECHNOLOGY REVIEW ............................ ERREUR ! SIGNET NON DEFINI. 4.1


4.2

C-MN STEEL PIPE – RIGID PIPE ............................................... ERREUR ! SIGNET NON DEFINI.

4.2.1

Steelmaking process: ........................................................ Erreur ! Signet non défini.

4.2.2

Seamless or seam welded pipe......................................... Erreur ! Signet non défini.

4.2.3

Main steel pipe manufacturers:.......................................... Erreur ! Signet non défini.

4.3

FLEXIBLE PIPE ........................................................................ ERREUR ! SIGNET NON DEFINI.

4.4

STAINLESS STEEL ................................................................... ERREUR ! SIGNET NON DEFINI.


SEALINES

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4.5

5

6

CLAD PIPE SYSTEM ................................................................. ERREUR ! SIGNET NON DEFINI.

4.5.1

Manufacturing procedures ................................................. Erreur ! Signet non défini.

4.5.2

Hot rolling process: ............................................................ Erreur ! Signet non défini.

4.5.3

Thermo-hydraulic fit method .............................................. Erreur ! Signet non défini.

4.6

WET INSULATED RIGID PIPE ..................................................... ERREUR ! SIGNET NON DEFINI.

4.7

PIPE IN PIPE SYSTEM............................................................... ERREUR ! SIGNET NON DEFINI.

4.8

PIPELINE BUNDLE SYSTEM....................................................... ERREUR ! SIGNET NON DEFINI.

INSULATION TECHNIQUES & SUPPLIERS.............. ERREUR ! SIGNET NON DEFINI. 5.1

PIPE IN PIPE SYSTEM............................................................... ERREUR ! SIGNET NON DEFINI.

5.2

INTEGRATED TOWED FLOWLINE BUNDLE SYSTEM ..................... ERREUR ! SIGNET NON DEFINI.

5.3

WET INSULATION PIPE SYSTEM ................................................ ERREUR ! SIGNET NON DEFINI.

5.4

FLEXIBLE PIPE ........................................................................ ERREUR ! SIGNET NON DEFINI.

HEATING TECHNIQUES ............................................ ERREUR ! SIGNET NON DEFINI. 6.1


6.2

ELECTRICAL HEATING SYSTEM ................................................ ERREUR ! SIGNET NON DEFINI.

6.2.1

SECT Heat tracing ............................................................. Erreur ! Signet non défini.

6.2.2

Combipipe Induction Heating............................................. Erreur ! Signet non défini.

6.2.3

Combibundle induction heating .........................................Erreur ! Signet non défini.

6.2.4

Direct heating.....................................................................Erreur ! Signet non défini.

6.3

7


HOT FLUID CIRCULATION HEATING SYSTEM .............................. ERREUR ! SIGNET NON DEFINI.

6.3.1

Hot water heated wet insulated pipe ................................. Erreur ! Signet non défini.

6.3.2

Hot water heated bundle / pipe-in-pipe system ................. Erreur ! Signet non défini.

6.3.3

Hot water heated flexible ...................................................Erreur ! Signet non défini.

BURIAL TECHNIQUES............................................... ERREUR ! SIGNET NON DEFINI. 7.1


7.2

PLOUGH TECHNIQUE ............................................................... ERREUR ! SIGNET NON DEFINI.

7.3

JETTING TECHNIQUE ............................................................... ERREUR ! SIGNET NON DEFINI.

7.4

MECHANICAL CUTTER TECHNIQUE ........................................... ERREUR ! SIGNET NON DEFINI.

7.5

BACKFILLING / ROCK DUMPING ................................................ ERREUR ! SIGNET NON DEFINI.

7.5.1

Introduction ........................................................................Erreur ! Signet non défini.

7.5.2

System description............................................................. Erreur ! Signet non défini.

7.5.3

Pre-lay pipeline support ..................................................... Erreur ! Signet non défini.


SEALINES

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8

9


INSTALLATION TECHNIQUES .................................. ERREUR ! SIGNET NON DEFINI. 8.1


8.2

S- LAY METHOD ...................................................................... ERREUR ! SIGNET NON DEFINI.

8.3

J-LAY METHOD ........................................................................ ERREUR ! SIGNET NON DEFINI.

8.4

REEL-LAY METHOD ................................................................. ERREUR ! SIGNET NON DEFINI.

8.5

TOW METHOD ......................................................................... ERREUR ! SIGNET NON DEFINI.

8.6

FLEXIBLE LAYING METHOD ...................................................... ERREUR ! SIGNET NON DEFINI.

INTERNAL CORROSION MONITORING ................... ERREUR ! SIGNET NON DEFINI. 9.1


9.2

PRINCIPLE .............................................................................. ERREUR ! SIGNET NON DEFINI.

9.3

ARRANGEMENT OF SENSING PINS ............................................ ERREUR ! SIGNET NON DEFINI.

9.4

MONITORING SYSTEM ............................................................. ERREUR ! SIGNET NON DEFINI.

10 APPLICATIONS & LIMITATIONS............................... ERREUR ! SIGNET NON DEFINI. 10.1 SEALINE TECHNOLOGY............................................................ ERREUR ! SIGNET NON DEFINI. 10.2 INSTALLATION TECHNIQUES ..................................................... ERREUR ! SIGNET NON DEFINI.

11 ADVANTAGES & DISADVANTAGES ........................ ERREUR ! SIGNET NON DEFINI. 11.1 C-MN STEEL PIPE ................................................................... ERREUR ! SIGNET NON DEFINI. 11.2 FLEXIBLE PIPE ........................................................................ ERREUR ! SIGNET NON DEFINI. 11.3 DUPLEX STAINLESS STEEL PIPE ............................................... ERREUR ! SIGNET NON DEFINI. 11.4 CLAD STEEL PIPE .................................................................... ERREUR ! SIGNET NON DEFINI. 11.5 BUNDLE SYSTEM ..................................................................... ERREUR ! SIGNET NON DEFINI. 11.6 PIPE-IN-PIPE SYSTEM .............................................................. ERREUR ! SIGNET NON DEFINI. 11.7 13% CR PIPE ......................................................................... ERREUR ! SIGNET NON DEFINI. 11.8 SUMMARY TABLE .................................................................... ERREUR ! SIGNET NON DEFINI.


SEALINES

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1

INTRODUCTION

1.1

Scope

The challenges of deepwater oilfields and inter-continental gas transportation present the biggest opportunities the pipeline technology faces today. Sealine new thermal insulation technologies will be required to assure that produced fluid will flow through long distance subsea lines, at low seafloor temperature. The scope of this study will cover the following topics: •

Give an overview of problems related to the transport of unprocessed and sometimes corrosive multiphase well streams in deepwater pipelines, in low ambient temperature and high external pressure environment, conducive to the formation of paraffin deposits, wax or hydrates (sections 2 and 3)

•

Review material and sealine technology currently available in the industry to overcome the above technical problems while keeping cost at competitive levels (section 4)

•

Provide information on flow assurance topics, insulation material and heating technique applied to deepwater pipeline, to mitigate the deleterious effects of wax and hydrate formation and internal corrosion (sections 5 and 6)

•

Give list of installation and tie-in methods dedicated to different types of sealine system including interface requirement, burial technique, etc. (sections 7 and 8)

•

Provide information on internal corrosion monitoring system ( section 9)

•

Finally analyse the applications and limitations, along with the advantages and disadvantages of each sealine technology and its installation methods (sections 10 and 11).


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1.2


Regulations, Codes, Standards & Specifications

‘’ Rules for submarine pipeline systems ’’, 1981 – (amended as needed by 1996 edition)

DnV

‘’ Guidelines for design, fabrication and installation, submarine pipelines and risers ‘’

N.P.D.

‘’ Submarine pipeline guidance notes ‘’

DoE

‘’ British standard code of practice - pipelines ‘’ ‘’ Pipeline safety code ’’

BS 8010 IP 6

‘’ Recommended practice- Control of internal corrosion in steel pipelines and piping systems ’’

NACE

‘’ B 31.4 Liquid petroleum transportation piping systems ’’

ANSI

‘’ B 31.8 Gas transmission and distribution piping systems ’’

ANSI

‘’ R.P. 1111 – Design, construction, operation and maintenance of offshore hydrocarbon pipelines ‘’

API

‘’ RP 14E - Design and installation of offshore production platform piping systems ‘’

API

‘’ Specifications for pipeline ’’

API 5L &.5LC

‘’Guide for gas transmission and distribution pipeline system 1080’’

ASME

‘’ Z 183 - Oil pipeline transportation systems ‘’

CSA

‘’ Z 184 - Gas pipeline systems ‘’

CSA

‘’ Submarine pipeline code ‘’

SAA

‘’ Gas pipeline code ‘’

SAA

“ Part 2 – Flexible pipe systems for subsea and marine applications” (in preparation to replace API RP 17B)

ISO 13628

“ Pipeline transportation system for the Petroleum and Natural Gas Industries “

ISO 13623


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1.3


Definitions & Abbreviations

Flowline = The conduct system e.g. steel pipeline, flexible line, bundle, etc; divided in two parts: "sealine" section resting on seabed and dynamic "riser" section from seabed to surface Sealine

= "Static" section resting on seabed of a conduct for the flow of liquid and/or gas

Pipeline = The conduct system uses to export oil and gas from fixed or floating production system to shore A&R

= Abandonment and Recovery

C-Mn

= Carbon-Manganese

CRA

= Corrosion Resistance Alloy

DGPS

= Differential Global Positioning System (Satellite positioning of DP vessel)

DP

= Dynamic positioning

DSV

= Diving Support Vessel

ERW

= Electric Resistance Weld

FBE

= Fusion Bonded Epoxy

FSM

= Field Signature Method

GTAW

= Gas Tungsten Arc Welding

HAZ

= Heat Affected Zone

HDPE

= High Density Polyethylene

HIC

= Hydrogen Induced Cracking

HP

= Horse Power

LCC

= Life Cycle Costing

LPM

= Liter per minute

GMAW

= Gas Metal Arc Welding

NDT

= Non-Destructive Testing

PA 11

= Polyamid 11

PC

= Personal computer

PEX

= Cross Wound Polyethylene

PUF

= Polyurethane Foam

PVDF

= Polyvinylidene Fluoride

PGMAW = Mechanised Pulsed Gas Metal Arc Welding ROV

= Remote Operated Vehicle

SAW

= Submerged Arc Weld

SCC

= Stress Corrosion Cracking

SECT

= Skin Effect Current Tracing

SSCC

= Sulphide Stress Corrosion Cracking

SWC

= Stepwise Cracking

TFL

= Through Flow Line

TFP

= Tight Fit Pipe

TMCP

= Thermo-Mechanical Controlled Processing

VIV

= Vortex Induced Vibration

VLS

= Vertical Laying Spread


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WD

1.4


= Water Depth

References 1. Offshore Technology Conference papers from 1969 to 1998 2. In-house technical database 3. In-house experience in rigid and flexible pipeline installation 4. Manufacturer and subsea contractor product leaflets

5. Deepwater Field Development – Reference Book – “Tie-in Methods” Document n° TOTAL/Z/EN-005/98 (SEAL Engineering)

1.5

Acknowledgements

We wish to thank the manufacturers and subsea contractors for the provision with courtesy of technical information and photographs of their products.


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2

PIPELINE DESIGN FOR DEEP WATER

2.1

Introduction

A typical deepwater flowline system is designed to transport produced fluids from several subsea wells directly or through a subsea manifold on to the floating production system via sealines and risers. In addition to the production flowline system, there are flowlines to export gas and/or oil to shore. Pipelines are far the most economical method for transporting large quantities of fluids. Other modes are more economical only when the quantities are too small to justify the capitol cost of a pipeline or where technical difficulties make it impossible to construct a pipeline. The principal technical difficulties are related to extreme depths, and occasionally to uneven seabed and to high currents. The primary factors that predict the difficulty of a deepwater pipeline project are the maximum depth (high hydrostatic pressure) and the diameter and weight of the pipe. A pipeline has to meet several design criteria. It has to be strong enough to resist internal pressure, which in force terms is usually much the largest load it has to carry. It has to be strong enough to withstand other loads applied during installation and operation, principally external pressure and bending, but also axial tension, torsion and shear. It may have to carry large concentrated loads applied by installation method. It has to be made out of materials which guarantee the life time of the pipeline under erosion and corrosion effects. It has to be heavy enough to be stable against hydrodynamic forces, but not so heavy that it sinks into the seabed or become over-stressed when it spans low points. It would be wrong to suppose that all these questions become more severe when the pipe is in deep water. On some instances, many of them become easier. Usually, though not always, the currents near the bottom are quite small in deep water, because surface wave action is insignificant more than half a wavelength below the surface, and because tidal flows are insufficient to generate high velocities because of the large flow cross-section. Most pipelaying techniques lay the pipe with the internal atmospheric pressure. In deep water, the pipe wall is then subject to a net external hydrostatic pressure during installation.. In operation, the pipe is subject to a net internal pressure, and the depth and hence the external hydrostatic pressure may serve to reduce the required minimum burst wall thickness, particularly if the selected wall thickness includes a corrosion allowance which will be present during installation and consumed during operation. The obvious difficulty is that external pressure may cause the pipeline to propagation buckling which is first initiated by a local buckling of the pipe wall due to external hydrostatic pressure, axial force and bending moment then run along the pipe under the effect of external pressure, collapsing the pipe into a dumb-bell cross section. Buckle propagation could destroy many miles of pipeline. The determination of pipe wall thickness to mitigate the buckling problem is presented in section 2.3 Pipeline Design Method. Some deepwater pipelines are designed so that the maximum net external pressure is lower than the propagation pressure, so that propagation cannot possibly occur. This becomes an onerous requirement in deep water, and a less conservative approach is to install buckle arresters, so that a buckle initiated by unexpectedly severe bending might propagate to the next arrester, but could not destroy a long length. The calculation and design of buckle arresters is a well known technique. External pressure governs the design of pipelines conventionally installed in deep water. This condition is most severe during installation, when the pipelines carries demanding combination of external pressure, bending and tension.


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2.2


Material selection

The selection of a material for a pipeline or flowline is a compromise between optimum corrosion resistance, required mechanical properties, fabricability, availability and cost. It may often be the case that a final choice has to be made between two or more optional materials which may differ in the extent to which they meet all the desired service requirements for the anticipated required lifetime of the project. In the extreme cases where corrosion risks are either negligible or very severe, material selection is fairly simple and a typical choice will be carbon steel or corrosion resistant alloys respectively. Between these two extreme cases, the final choice of material may lie between carbon steel, with corrosion allowance and coating, cladding or inhibitor protection, or various corrosion resistant alloy options. In this situation, past practice may have been to select the option which requires the least upfront capital expenditure. Increasingly, however, the selection of materials is being made not simply on what is immediately the cheapest technically acceptable option, but on a longer term view of the costs incurred for the duration of a project. The Life Cycle Costing (LCC) approach utilises established accounting methods to compare the costs of alternative materials selections by calculating the ‘’present day value’’ of future costs associated with the chosen materials. By using LCC it can often be demonstrated that paying out more at the start for corrosion resistant alloys rather than an apparently much cheaper material, results in substantial savings in operating, maintenance and repair costs in the future. One of the key benefits of using LCC in a comprehensive way is that it obliges the user to take a global view of the issue in question and not to solve a single problem in isolation of all the other factors which are affected or may affect the decision making process. Each case has to be calculated separately taking into consideration the material dimensions, fabrication method and pipe laying rate for the different materials, oil/gas production rate, inhibitor or glycol injection rate for carbon steel, appropriate inspection methods and frequency, etc.

2.3

Pipeline design method

2.3.1. General consideration The pipeline design calculations aim to determine the pipeline characteristics, such as external diameter or wall thickness, which will allow it to withstand not only the requirements of the production phase (resistance to the internal pressure and corrosion, stability on the seabed despite the seabed current forces, etc.) but also the installation loads (external pressure if the pipe is installed air filled, bending and compression forces, tension, etc.). In the past, pipeline design or rules were based on allowable stresses computed from the material Specified Minimum Yield Strength to which a usage factor is applied (typically from 0.7 - 0.9 depending on the load cases). The last few years have seen the introduction of reliability-based Limit State Design (LDS) for offshore pipeline, this is a radical change in design philosophy as its application is based on risk assessment and probabilistic approaches. The relatively recent code DNV 96 which is based on the Limit State Design, has been first used for the design of the Asgard 42" x 700 km gas trunkline. Pipeline design is a key issue within the offshore oil & gas engineering disciplines, and is outside the scope of this document. However, the following section aims to describe a typical pipeline design approach and its general philosophy based on the DNV 96: “Rules for submarine pipeline systems”.


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During the design phase, the following points will be checked out: 1.

Pipe material selection (based on produced fluid chemistry)

2.

Pipe inside diameter

3.

Pipe wall thickness 3.1 3.2

Internal pressure containment Hydrostatic collapse

3.3

Local buckling

3.4

Buckling propagation

4. 5.

Stability check Span calculations

6.

Pipe expansion calculations

7.

Upheaval buckling

2.3.2. Pipeline diameter determination. The design basis fixed the pipe inside diameter by fluid flow considerations. This is mainly based on the fluid properties such as the viscosity, the expected pressure at the well head, the flow rate, etc.

2.3.3. Pipeline wall thickness. A first wall thickness evaluation is performed using the following criteria: • Internal pressure containment: The tensile hoop stress σh is to fulfil: σh < ηs . SMYS σh < ηu . SMTS where:

σh = (pi – pe) . (D-t) / (2 t) (Mpa) pi, pe are the internal and external pressures (Mpa) D is the pipe outside diameter (mm) t is the pipe wall thickness (mm) SMYS is the minimum specified yield strength (Mpa) SMTS is the minimum specified tensile strength (Mpa) ηs, ηu are usage factors typically within 0.64-0.96 (see DNV 96, section 5 C204)


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• Hydrostatic collapse: The wall thickness must satisfy: p e<

where:

pc 1.1. γ r

pc is the pipe collapse pressure and depends on the wall thickness, the diameter, the Young modulus (E), the Poisson coefficient (ν), the minimum specified yield strength (SMYS) and the ovalisation (see DNV 96 section 5C306) (Mpa). pe is the external pressure (Mpa). γr is the resistance factor (typically between 1.19 and 1.58).

• Buckling propagation: The design is based on this criterion if no buckle arrestor is expected on the pipeline. The buckling propagating pressure is to fulfil: ppr > pe where:

ppr = 26 . SMYS . (t/D)2.5 (Mpa)

All these criteria allow to define a first wall thickness that will then be checked during the following design phases. A corrosion allowance must be considered (depending on the corrosivity of the environment, of the producing fluid and on the inspection means). This corrosion allowance is not to be taken into account for resistance calculations during operation but can be considered for the installation phase.


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2.3.4. Dynamic calculations. Dynamic calculations, modelling the installation phase, are then performed using time domain simulation based software such as Orcina, Deepline, Flexcom 3D, etc, and static forces resulting from adequate laying analysis. Local buckling verification allows to check whether the pipeline will suffer buckling or not, and so to eventually re-adjust the wall thickness. The local buckling condition can be written: γ f. γ c . M f

where:

γ e. M e

2

pe

Mc

pc

γ r

γ r

2

<1

Mf is the characteristic functional bending moment (kN.m) Me is the characteristic environmental bending moment (kN.m) Mc is the characteristic limit bending moment (kN.m) pe is the external pressure (Mpa) pc is the collapse pressure (Mpa) γf, γe, γc are load factors (typically between 1 and 1.3, see DNV 96 section 4) γr is the strength resistance factor

2.3.5. Stability check. The embedment and the stability of the pipeline depends on the soil characteristics, on the current loads (and wave loads when considering shallower conditions or area with internal waves), on the overall outside diameter and on the weight of the pipe. Checking the horizontal and vertical stability of the pipe aims to eventually adapt its diameter and weight, for example by adding a concrete layer if necessary. The DNV 96 gives, as primary verification, a simple calculation method for the on-bottom stability check but more accurate methods ( dynamic analysis) can be employed. The DNV 96 static analysis method may be expressed by: γ . (Fd – Fi) < µ . (W sub – FL) where:

γ is a safety factor (>1.1) Fd is the hydrodynamic drag force per unit length (N/m) Fi is the hydrodynamic inertia force per unit length (N/m) µ is the lateral soil friction coefficient (provided by American Gas Association Research) W sub is the submerged pipe weight per unit length (N/m) FL is the hydrodynamic lift force per unit length (N/m)


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2.3.6. Span calculations. The length of unsupported spans on an offshore pipeline may support excessive stress due to its own weight and transported fluid mass. Moreover, spans exposed to flow of seawater due to currents and waves are subject to a phenomenon commonly referred to as vortex shedding. Span calculations are performed either to determine the maximum allowable span length in order to check that no problem concerning spanning will occur or to define a new wall thickness that allow the pipe to withstand the non-even support conditions expected. Span calculations are based on both a static analysis, which check that the pipe can support its own weight, and a dynamic analysis which verify that either no VIV occurs or that it is acceptable regarding the fatigue life. The maximum allowable span length static calculation, based on formula of strength of materials, may be written as follows:

L

where:

16.

I . SF. SMYS . . DgWs

0.5

L is the maximum allowable span length (m) D is the outside diameter of the steel pipe (m) Ws is the submerged weight per unit length of the pipeline (N/m) g is the acceleration due to gravity (m/s2) SF is the safety factor (typically 0.5) SMYS is the minimum specified yield strength (Pa)

Determining the maximum allowable span regarding VIV aspect can be performed, as a primary study, by determining the maximum first natural period of the pipe spanning part which avoids VIV (i.e. a first natural period out of the VIV period range). Two sorts of VIV may occur: the in-line oscillations and the cross-flow oscillations ("in-line" means parallel to the current direction). Even if the cross-flow vibrations are of primary interest regarding the fatigue damages, the in-line oscillations are the most stringent when considering the natural periods.


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The maximum natural period of the pipe to avoid VIV can be defined as follows:

T max

where:

V r.max. D o V

Tmax is the maximum natural period of the pipe (s) V is the current velocity (m/s) Vr.max is the maximum reduced velocity, determined by the following empirical curve and the parameter Ks (See figure 01):

Ks

where:

2. m e. δ 2

ρ sea. D o

me is the effective mass per unit length of the pipeline (kg/m) δ is the logarithmic decrement of structural damping (typically 0.1885) ρsea is the sea water density (kg/m3) Do is the overall outside diameter (m)

Figure 01- Reduced flow velocity for onset of in-line motion


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The corresponding maximum span length is defined by the expression of the first natural bending period of the equivalent beam:

L

where:

0.5 0.5

I C. T max. E. me

L is the maximum allowable span length (m) C is a support condition factor (about 2.5) Tmax is the maximum natural period of the pipe (s) E is the Young modulus (N/m2) I is the inertia modulus of the pipe section (m4) me is the effective mass per unit length of the pipeline (kg/m)

2.3.7. Pipe expansion calculations. The pipeline experienced internal compression forces due to pressure and temperature variations. An estimation of these efforts allows to check that they are acceptable and to determine the dilatation length. The compression force can be taken as:

T comp

where:

N

pi

π 2 p inst . . D i . ( 1 4

2. ν )

A. E. T

T inst . α

T comp is the compression force (N) N is the residual axial tension (after installation) (N) pinst is the internal pressure (installation) (Mpa) pi is the internal pressure (operation) (Mpa) Di is the internal diameter (mm) ν is the Poisson coefficient E is the Young modulus (Mpa) A is the steel cross sectional area (mm2) Tinst is the internal temperature (installation) (°K) T is the internal temperature (production) (°K) α is the thermal expansion coefficient (°K-1)

The pipe expansion calculation depends on the soil friction coefficient, on the manner the pipe is laid on the seabed (whether embedded or not), on the boundary condition, etc.


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2.3.8. Upheaval buckling. The above compressive force could be the cause for upheaval buckling appearance (i.e. pipeline local elevation due to the thermal expansion). Buried pipelines operating at high temperatures and pressures may also experience upheaval buckling due to compressive loads resulting from the axial restraint of the soil and imperfections in the seabed or uneven burial depth. Some calculation methods can be found in the literacy, trying to model the pipesoil interaction and to anticipate the problem. These methods can be used to design the required embedment depth of the pipeline if upheaval buckling appearance is expected. For embedment depth, a pipe-soil interaction model gives the following formulae:

qs

where:

H f. Do

γ . g. H. D o. 1

qs is the uplift resistance of a cohesionless sand cover (N/m) γ is the submerged weight of the soil (kg/m3) g is the acceleration due to gravity (m/s2) H is the height of cover (m) Do is the outside diameter of the pipeline (m) f is an empirical uplift coefficient (typically between 0.1 and 0.5)

The total downwards force is hence equal to: W sp . g

Where:

qs

W sp is submerged weight of the pipeline (kg/m)

This force must be greater than the upward force due to the thermal expansion and unevenness of the soil. A model gives the following force: 1

w

where:

δ . W sp . g T comp. EI

1

2

. 1.16

. . 4.76 . EI W sp g T comp δ

2

w is the upward force (N/m) Tcomp is the compressive force (N) EI is the bending stiffness of the pipeline (N.m2) δ is the average unevenness height at the considered location (m)

The above basic design phases must be considered as part of a "design spiral" as some iterations are required to define the pipeline characteristics. Other design phases or criteria can be added, such as the insulation calculations, depending on the pipeline system.


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2.4


Design Based on Local Buckling Criteria versus Buckling Propagation Criteria

For deepwater pipe lay projects, with the adoption of limit state design factors which allow design to be based on specific risk failure modes, the current trend is to design the pipeline against the local buckling criteria instead of the buckling propagation criteria (i.e. the later criteria will result in a higher pipe wall thickness) based on the following reasoning : • risk assessment - the pipeline is exposed to the maximum load case during the installation phase which is limited in time (e. g. days or weeks) versus its life cycle (e.g. 20 to 30 years), the contingency in case of pipe buckle would be to relay a line • cost consideration - the adoption of the local buckling criteria will result in substantial gain in steel pipe procurement and offshore installation cost, up to 30 % cost saving (versus the buckling propagation design basis) • technical consideration - the lay tension of a typical API 10" pipeline at 2000 m water depth is some 400 tons (based on buckling propagation criteria) which is the tensioner limit for the latest deepwater lay vessel (i.e. Allseas Solitaire) when local buckling criteria will concede 140 tons lay tension which is more in line with most current deepwater lay vessel capabilities.

2.5

Radical Alternative Approach in Deepwater Pipeline Lay

The design of pipeline in deep waters is conventionally governed by the large external pressure which implies a large wall thickness, as most pipeline are laid in 'air' at surface atmospheric pressure so that the submerged weight shall be small. Once the pipeline is in service, it only has to withstand the positive difference between the pipeline internal service pressure and the external hydrostatic pressure. It follows that the additional wall thickness steel requirement to resist external pressure during laying is wasted. The conventional thinking is that a water-filled pipe would be unacceptably heavy, and that the pipe must be laid air-filled to be within laying equipment acceptable range. This is true in shallow water. In deep to ultra deep water it is not longer true. Certain design engineering companies and laying contractors are looking into the field of water-filled pipe lay possibilities, based on the following general lay tension results : • water-filled pipe required less lay tension than heavy wall (propagation buckling requirement) air-filled pipe as off the 1000 m water depth range • water-filled pipe start to be lighter than thickener wall (local buckling requirement) airfilled pipe as off the 2500 m water depth range There are many cost advantages to lay pipeline liquid-filled (1) by reducing the cost of steel procurement, (2) which in terms required less offshore spread time (less welding time on thinner wall pipe) and (3) to prevent the excessive capital expenditure for the upgrading of laying equipment and vessels.


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3

INTERFACE REQUIREMENT

3.1

Introduction

Development of the field requires several subsea wells to be drilled at different water depths and locations. These wells will be connected by means of sealines and risers to floating production system positioned near the field. The main interface requirement in the sealine design is related to: •

Pipeline end terminations

•

Subsea production system

•

Subsea connection and tie-in methods

•

Lay vessels and methods

For the interface requirement related to subsea connection, please refer to the document "Tie-in Methods" (Reference 5) of Deepwater Field Development - Reference Book.


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3.2



A typical rigid steel pipe is terminated either with a flange or hub for future clamped/bolted connection or with a pipeline end module (PLEM) consisting of an emergency shut down valve, a horizontal or vertical connection hub, and a swivel to assure that the PLEM will be installed within the designed inclination tolerances in order to allow the direct horizontal or vertical connection (see figures 02 and 03). Horizontal Connector

Sealine terminated with male hub Figure 02 - Male hub mounted on pipeline end termination

Flexible terminated with gooseneck and female connector

Vertical connector PLEM terminated with flange for connection to sealine Figure 03 - Pipeline end manifold (PLEM) terminated with a flange connector


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The flexible pipe structure is terminated with end-fittings at both ends (see figures 04a, 04b and 04c). This end-fitting provides a link between the unbonded layers of the structure and a flange which allows for connection with the floating production platform, rigid/flexible lines or sled piping. Each end-fitting is an assembly of several steel components.

Figure 04a - CSO end fitting mounting

Flexible line Figure 04b – NKT end fitting concept End fitting

Bolted flange connection

Figure 04c – Flexible intermediate connection at working platform


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3.3



The subsea manifold system or the riser base, where the sealine will be connected to, must be designed and equipped with due consideration of the following additional mechanical aspects (see figures 05 and 06): •

Space/dimension provision for the selected connector, the tie-in tools and ROV operations

•

Permanent and temporary subsea hardware related to the tie-in method

•

Connection/reaction loads which vary with the tie-in method

•

Resist to the in-service load conditions such as temperature, slugging, etc.

Subsea hardware used for the diverless connection of pipelines and permanently mounted on subsea structure or landed on seabed are as follows : • pull-in sheave and rigging • landing base for running tools • ROV platform • alignment modules • pipeline end termination • subsea winch The following are examples of subsea hardware temporarily mounted on subsea structures in order to perform the desired tie-in : • buoyancy modules • winch and cables • protection caps • blind and test caps • pull-in/connection tool and pull-in head • positioning and measuring equipment • pig launcher / pig receiver


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ROV panels

Preinstalled clamp connector for connection to sealine

Figure 05 – Deepwater subsea manifold

Satellite tree

Pre-installed male hub for connection to sealine Subsea cluster manifold

Figure 06 – Subsea cluster well system


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3.4


Installation vessels

Outwith the tow method for the installation of bundle, there are three (3) main laying techniques that can installed rigid pipelines in deep water: • Steep S-Lay • J-Lay • Reel-Lay Each above laying method will induced high dynamic load onto the pipeline with different cumulative and residual strains which need to be addressed in the pipeline design. In deepwater applications, flexible pipelines are mainly installed using the J-Lay method with tensioners integrated in a laying ramp or a dedicated vertical flexible laying system. The typical dynamically positioned lay vessels are hereafter illustrated:

Firing line

Figure 07 – Steep S-Lay vessel: Allseas Lorelay (1998 record, 12" Marlim rigid export line in 1650m)


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J-LAY ramp

Figure 08 – J Lay semi-submersible: Heerema Balder (30" rigid pipelay capability and up to 2000m WD)

Lay ramp

Pipe storage Reel

Figure 09 – Reel-Lay vessel: CSO Apache (1998 record, 12" rigid reeled gas line in 1373m WD)


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Flexible vertical laying spread

Lay ramp

Firing line

Figure 10 – Combined flexible & rigid pipe lay vessel: Seaway Falcon (500m WD 12” flexible and rigid pipe lay capacity)

Flexible vertical laying spread

Flexible storage carousel

Figure 11 – Dedicated flexible pipe installation: CSO Sunrise (2500m WD 12” flexible pipe lay capacity)


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4

SEALINE TECHNOLOGY REVIEW

4.1

Introduction

For the deepwater field development, the following sealine material and technology are readily available: Material : •

Carbon-Manganese steel pipe

•

Duplex and Super Duplex stainless pipe

•

Stainless steel

Technology : •

Wet insulated rigid pipe

•

Flexible pipe

•

Pipe-in-pipe system

•

Pipeline bundle system

•

Clad pipe system

The following sections will further describe the above material and technology. 4.2

C-Mn steel pipe – Rigid pipe

Currently, it is believed that most line pipe steels are made by either basic oxygen or electricarc furnace steelmaking. Another steelmaking process called open-hearth steelmaking, if still available, should be avoided because it doesn’t allow for the production of clean and lowcarbon steel. The two former processes can produce line pipe steel of acceptable quality. 4.2.1

Steelmaking process:

The making of steel by the basic oxygen process or in an electric-arc furnace can result in material with lower carbon and lower sulfur contents. Materials with lower carbon contents have lower ductile-to-brittle transition temperature and are more readily weldable. Reduction in the sulfur content tends to reduce the occurrence of elongated non-metallic sulfides. The latter are quite detrimental to ductile toughness and are especially detrimental in skelp destined to make into electric resistance welded (ERW) line pipe or in any material that may be exposed to H2S in service. Aside from the steelmaking process, a producer may also employ ladle processing to further reduce the sulfur content and to introduce beneficial alloying elements. In most cases the molten steel in the ladle, shrouded from contact with air, is poured into a continuous slab or strand caster. These casters allow the steel to solidify at the outside surface while remaining molten internally to a point below the ladle outlet. The internally molten steel may be stirred magnetically or subjected to ‘’soft reduction’’ to prevent alloy segregation. Spray cooling is used to lower the temperature of the slab or strand as it is gradually curved into a horizontal position. A resulting slab is sent to a hot-rolling mill ; a strand is generally cut into billets for making seamless pipe.


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4.2.2


Seamless or seam welded pipe

Most line pipe is made as seamless, electric-welded, or furnace butt-welded pipe. Furnace butt-welded pipe is so limited in size and grade that is not a practical method for making pipe for high pressure pipelines. Therefore, the practical choices evolve to seamless and electricwelded pipe. The seams of electric-welded pipe may be electric resistance welded (ERW) or submerged-arc welded (SAW). Other seam welding processes (Gas metal arc welding MIG, combination of gas metal arc welding and submerged arc welding) are recognised by API specification 5L, but they are apparently not widely used. •

Seamless pipe: Seamless pipe is made one round at a time from single billets by one of several possible multi-step hot-forming processes. However the general process is practically the same: - Heating of cylindrical or parallelepipedic billets up to 1300°C - Piercing of billets (1150 – 1250°C) (see figure 12) - Lamination at 1000 – 1100°C to obtain the required thickness (see figure 13) - Final calibration (800 – 900°C) to fixe the external diameter - Cut from the resulting pipe (12m long or more) to the desired length


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Pipe Mandrel

Cylindrical billet Guiding roller

Figure 12 – Billet piercing process

Mandrel

Cylinder

Pipe

Diameter reduction

Thickness reduction

Thickness regulation

Diameter regulation

Figure 13 – Continuous lamination As a result it is generally more expensive, than welded pipe. It is made in sizes ranging from 2 3/8-in diameter through 24-in diameter and in grades from Grade A through Grade X60. It may be obtainable in higher grades but such materials may require special heat treatment. If so the cost will likely be quite high relative to welded pipe.


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•


Electric resistance welded pipe:

ERW line pipe is made from coiled skelp in a continuous process where the strip is edge trimmed and cold-formed from its initial flat condition into a round shell. As the edges of the strip are brought together electric current is passed between them heating them locally to the point of melting or near melting just as they are forced together by a pair of rollers bearing on the unheated portion of the shell (see figure 14). The pressure forces the heated edges together, upsetting excess material to the outside and inside. The excess ‘’flash’’ is trimmed from both surfaces. In most ERW processes the just-completed weld zone is then immediately subjected to post-weld heat treatment. The weld zone is reheated to a temperature which ‘’normalises’’ the microstructure in the area of the bondline minimising or eliminating possibly unfavourable microstructural components created during welding. Pipe segments of the desired length are then cut from the continuous tube. In a few ERW mills the finished tube is subjected to ‘’full-body’’ normalising where the whole tube is heated to the normalising temperature. In either case the pipe is sized by passing it through rolls. ERW line pipe is obtainable in sizes ranging from 2 3/8-in diameter through 24-in diameter and in grades ranging from Grade A through Grade X70. A few manufacturers may offer Grade X80 ERW pipe. However, ERW pipe is not commonly used in deepwater applications,.

Pipe Roller Electrical electrodes

Pipe Induction current

1

Induction Welding

2

Resistance Welding

Figure 14 – Electric Resistance/Induction Welded pipe


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•


Submerged arc welded pipe The third type of line pipe is that made from individual plates with a submergedarc welded seam. Typically, very large diameter, heavy-walled line pipe materials are made by this process. The process begins with the plates being squared at the ends and edge trimmed and bevelled along the long edges. The plates are then cold-formed into ‘’cans’’ roughly 40-feet in length. In some cases the cans are formed in stages including edge-crimping, U-ing (forming to a U shape) and O-ing (pressing the cans to a round shape). U-O pipe is generally cold-formed (expanded) to its final size after being seam welded by mechanical or hydraulic means (see figure 15). In other cases the cans are formed by means of pyramid rolls and the pipe is sized after being seam welded by means of rolls in much the manner as ERW pipe is sized.

The seam-welding of SAW pipe is done in two passes both in the flat position, one from the ID side and one from the OD side. Usually the ID pass is made first by means of a three-tofive wire welding head. The pipe is then turned 180 degrees, and the OD pass is made with a two or three-wire welder. No post-weld heat treatment is required. Factors which can affect quality are the filler-metal chemistry and flux chemistry and the manner in which the first pass is made. Holding the edges in the proper position and preventing relative movement while the first pass solidifies are essential. For this reason some manufacturers tack weld the edges of the cans prior to seam welding. Others rely solely on mechanical restraint.

Edge trimming

Internal welding

External Welding

U Forming

Matrix Pipe O Forming

Expansion

Figure 15 – Submerged Arc Welded pipe fabrication process


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Straight-seam SAW pipe is obtainable in sizes ranging from 16-in OD through 48in OD (larger sizes may be available from manufacturers in Europe or Japan) and in grades from Grade A through Grade X70. Grade X80 materials may be available through certain manufactures. SAW pipe is also obtainable with a spirally-oriented seam (see figure 16). External welding

Internal welding

Figure 16 – Spirally-oriented seam welded pipe In this process, the plates are welded end-to-end so that a continuous strip is fed at the proper prearranged angle to a forming stand. The spiralling strip is then continuously welded along the incoming edge into a round tube. Both an ID and an OD pass are made. Pipes of the desired length are then cut from the resulting continuous tube. Finally, if the pipe is to be coated with fusion-bonded epoxy, the pipeline surface condition should be suitable for coating. The main problem to be avoided is surface slivers which, when raised by grit blasting and heating, cause severe coating defect problems. In deepwater applications, SAW pipes are not commonly used except in bundle configuration where the carrier pipe may be made from SAW pipe as a cost effective alternative to seamless pipe.

4.2.3

Main steel pipe manufacturers:

The main steel pipe manufacturers are : •

Europipe (Mannesman of Germany and Usinor Sacilor of France)

•

US Steel (USA)

•

Sumitomo (Japan)

•

Nippon Steel (Japan)

•

Kawasaki (Japan)

•

NKK (Japan)

•

CONFAB (Brazil)

•

Etc.


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4.3


Flexible pipe

There are only three (3) flexible pipe manufacturers listed below: •

Coflexip Stena Offshore (World Leader)

•

Wellstream (Halliburton – Dresser Group)

•

NKT (Danemark)

The "Coflexip" product of flexible pipe have been extensively used in Brazil Campos Basin since 1977. The world deepest application (at report date) was reached last year on Petrobras Marlim Sul with 4" ID x 12km oil flexible line tied back of 2 wells at 1710m. With the introduction of the "Teta spiral" technology by Coflexip and the application of composite material, it is generally agreed that this technology has reached its maturity as follows: Maximum size

12 " ID

16" ID

Deepwater application Ultra deep water (under development)

1400m 2500m

1000m 1500m

Design service (internal) pressure

3000psi

3000psi

NKT has been manufacturing flexible subsea pipes since 1968 and has been collaborating with the FURUKAWA Electric Co. Ltd (FEC) for more than 10 years concerning the development of flexible pipe technologies. The first flexible pipe produced and laid in 100m WD by NKT was a ID 4-inch water drinking flexible pipe with a pressure rating of 70 bar. NKT’s first high pressure offshore pipe for the oil industry was delivered in 1991 to Maersk Oil and Gas AS for installation at the DAN field in the Danish sector of the North Sea, consisting of a 500m long, ID 4-inch water injection pipe with a design pressure of 4,000 psi. NKT’s dynamic risers for dynamic applications use C-shaped steel profiles for internal pressure containment whereas CSO flexibles utilise Zeta or Teta profile. NKT’s product range starts from ID 2-inch to 14-inch with a design pressure of 10,000 psi and 3,000 psi respectively, both in static and dynamic configurations. The maximum design temperature is 130°C when PVDF is used as polymer material for fluid barrier.


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The structure of a typical flexible pipe, produced by either CSO or NKT, is shown in figure 17:

1

2

3

4

5

Figure. 17 - Typical flexible pipe structure for produced fluid The various layers constituting a typical flexible pipe are detailed hereafter, from the inside part of the pipe to the outside : 1.

Interlocked steel carcass (made of profiled stainless steel strips): to provide mechanical resistance to radial forces either from internal pressure, hydrostatic collapse or crushing loads, and to resist wear resulting from the use of scraper pigs and Through Flow Line tools.

2.

Pressure plastic sheath (e.g. made of polyamide) : to make the flexible pipe leak proof and immune to corrosion. The material used depends on the characteristics of the conveyed fluid (e.g. type, temperature, pressure, etc.) and the working conditions of the pipe (e.g. static, dynamic, etc.)

3.

Zeta or Teta spiral ( made of Z-shaped or T-shaped carbon steel wire wound around the inner layer) : to resist to hoop stress due to the internal pressure and to external crushing loads

4.

Armours layers (made of two or more crosswound layers of carbon steel wires) : to provide the high tensile strength of the pipe whilst also acting as a weighting layer which can be adjusted to meet particular stability requirements. Moreover, they give remarkable torsional stability

5.

External plastic sheath (e.g. made of grade of polyamide) : to prevent corrosion or abrasion of the metallic layers inside the structure and to bind the under layer of amours. It is a continuously extruded thermoplastic layer which prevents build-up of marine growth.


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The list of material used in flexible structure is shown in the following table: Designation of layer

Material used

Thermoplastic tube

Polyamide 11, High Density Polyethylene, Coflon

Interlocked steel carcass

Galvanized steel, AISI 3O4, AISI 304L, AISI 316, AISI 316L, Duplex, etc.

Thermoplastic sheath


Teta spiral or hoop strength layer

Low or medium carbon steel

Reinforcing layer

Low, medium or high carbon steel

Thermoplastic friction sheath

Polyamide 11, High Density Polyethylene

Double crosswound armors


Insulation foam

Cofoam, Carazide

Table 1 – List of material Note : •

Fabric tape is placed above the crosswound tensile armours to bind the under layer of amours during manufacturing before the external plastic sheath is extruded.

•

Antifriction tape (made of polyamide) is applied above the Teta layer to avoid friction and wear between the Teta layer and tensile armours. It is also placed between the two layers of amour.

•

If necessary for extreme high pressure, the interlocked layer is reinforced by a flat steel layer which is not interlocked.

•

For deepwater applications, armour layers made out of fiber glass and carbon have been produced and tested in 1000m WD in Brazil. No further development is planned for this type of flexible due to economical and technical limitations: high cost, requirement for high quality control in mass production of uniform composite material, difficulty to link the composite armour layers to the steel end fitting, etc).


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A typical ''smooth bore'' water injection flexible is shown on figure 18.

1

2

3

4

5 6

Figure 18 - Water injection flexible line From the inside, it is composed of the following: 1.

thermoplastic inner tube provides water tightness

2.

double zeta pressure carcass resists internal pressure and external radial forces

3.

intermediate thermoplastic sheath ensures the pipe is internally leakproof

4.

double crosswound tensile armours resist axial and torsional forces

5.

thermoplastic outer jacket protects the pipe from external corrosion and fluids

6.

stainless steel outerwrap (carcass) protects the thermoplastic outer sheath against mechanical damage (impacts, wear, handling, etc.)

The maximum design pressure of typical flexible structures in the range from 2 – 16-inch are represented in the following table 2: ID (in) Design pressure (psi)

2

4

6

8

10

12

14

16

10,000

7,500

7,500

5,000

5,000

5,000

3,000

3,000

Table 2 – Design pressure of current flexible pipes Remarks: The above information should be compounded with the water depth capability to define the overall technical characteristics of a flexible.


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4.4


Stainless steel

When the use of carbon steel is not possible because: • high corrosion rates are expected ; consequently high corrosion allowances are necessary, • corrosion inhibition is not feasible • a coating cannot be used then stainless steel must be considered. Two of the most widely used methods to produce stainless steel pipe are shown in figure 19. Melting steel

1. Centrifugation Process Matrix

Tube in progress

Driving wheel

2. Hot Extrusion Process Block-9,000 ton station

Trim-3,000 ton trim station

9,000 ton press pipe preforming sequence

Pierce-9,000 ton station

Upset–3,000 ton station 30,000 ton press pipe

Extrusion throat

extrusion sequence Trim

Extrusion container

punch I.D. punch

Figure 19 – Different types of stainless steel fabrication process The seamless hot-extruded pipe is produced on the 30,000 ton hydraulic press in the range of 150 – 1200mm Diameter, 10 – 200mm Wall Thickness and 16 metre maximum individual length.


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It is desirable that the material should be easily welded. This means, in terms of corrosion, that the weldments must exhibit mechanical properties and a corrosion resistance similar to the base material. 13% chromium steel, widely used for wells to mitigate against CO2 corrosion in the absence of H2S, is much less utilised in surface installations. Austenitic Stainless Steel type 316L (very low carbon content or stabilised to avoid intergranular corrosion) and the various austenitic-ferric steels (Duplex) have a better weldability and above all a better corrosion resistance than 13% Cr steel. However, they are very sensitive to corrosion pitting. An intensive welding qualification programme has been set up for the Asgard project to allow the implementation of 13%Cr steel as flowline material. The use of these materials for sealine is viable even though the cost is greater than carbon steel.


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4.5


Clad pipe system

The need for transport unprocessed corrosive multiphase well streams has increased interest in clad corrosion resistant alloy flowlines as an alternative to installing inhibited carbon steel. Handling unprocessed corrosive fluids then raises the issues of reliability, safety, and the costs of possible failures. Although the initial capital costs of a clad pipeline are quite high, the subsequent operating cost over the life of the project are relatively low. The opposite is true for carbon steel where relatively low initial costs may be coupled with significant operating and repair costs. For this reason, a life cycle cost analysis provides a better measure of the overall costs of clad versus carbon steel flowlines. 4.5.1

Manufacturing procedures

There are typically two (2) different clad pipe manufacturing processes: !

Hot rolling process

!

Thermo-hydraulic fit method.

There are two methods for the hot rolling process: !

Thermo-mechanical control process to clad pipe

!

As-quenching type heat treatment on welded clad pipe

These processes and methods are described hereafter: 4.5.2

Hot rolling process:

Figure 20 shows typical hot rolling clad pipe manufacturing process. Cleaning

Slabbing

Assembling

Plate Rolling

Backing Steel (C-Mn steel)

TMCP

Conventional

Clad Metal (AISI 316L)

UO Pipe Forming

SAW For Base Metal

Mechanized GTAW For Overlaying

Expansion

Example of clad pipe structure Quenching

Sizing

Pipe Finishing

Figure 20 – Hot rolling clad pipe manufacturing process Rev. 0 30/09/2000

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In the clad pipe manufacturing process, the clad metal and the backing steel are metallurgically bonded by hot rolling process after slab assembling. Two types of rolling processes are used: " One is the application of the thermo-mechanical control process to clad pipe, in which no heat treatment is applied on the clad plate or the welded clad pipe (TMCP plate process) " The other is conventional rolling process with as-quenching type heat treatment on welded clad pipe by induction heating in a short time (pipe quenching process). The selection from these two processes is determined by taking account of the cladding materials and required properties. In the application of TMCP to clad plate rolling, it becomes difficult to obtain both high strength and good toughness of backing steel when wall thickness is increased. Asquenching type heat treatment on welded pipes is useful for heavy wall thickness or superior toughness requirement. Quenching from relatively high temperature is also effective to improve corrosion resistance of the clad metal even if the corrosion resistance is deteriorated by hot rolling or longitudinal seam welding. Longitudinal seam welding procedure consists in first welding backing steel by submerged arc welding (SAW) with one pass in each side, and next performing an overlay welding in two molten pools by tandem Gas Tungsten Arc Welding (GTAW) with the hot wire method. Finally, inner surfaces of welded clad pipes are polished with wet brush to remove weld scales and to smooth the surfaces, otherwise they deteriorate corrosion resistance of the weld through the crevices created under weld scales.

4.5.3

Thermo-hydraulic fit method

Clad pipe can also be manufactured using the ‘’thermo-hydraulic fit method’’ as shown in figure 21, which is, in principle, a combination of the ‘’thermal shrink-fit method’’ and ‘’hydraulic expansion method’’. This technique allows to produce economically long lined pipe with high fit-in stress. The principle and the procedure of this method is as follows : Into an outer pipe which has been heated and thermally expanded, a liner tube is inserted and expanded by hydraulic pressure. After removing the pressure and heat in the outer pipe, the tight fitted lined pipe (TFP) is obtained. By this method, the accuracy of fitting is achieved by plastic expansion of the liner tube and the desired fit-in stress is achieved by thermal shrinkage of the outer pipe. By the use of this manufacturing procedure, many problem inherent to usual lined pipes, such as implosion, stress corrosion cracking and general corrosion, have been solved. Dpo

DLO

Inserting Liner Tube

Outer Pipe Thermal Expansion

Depression & Cooling Hydraulic Expansion

Figure 21 - Thermo-hydraulic Fit Method For Tightly Fitted Lined Pipe Rev. 0 30/09/2000

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4.6


Wet insulated rigid pipe

The design of a deepwater wet insulated rigid pipeline is based on the following considerations : • to be safely placed on seabed during deep water installations • to have an operating temperature up to 120°C • to be able to fit for all the different laying methods, and especially reeling puts stringent flexibility requirements to the pipe as external coating could be exposed to more than 2% elongation when reel-laid. From the above, a typical wet insulated system consists of (see figure 22): • Thick and rigid pipe made in carbon-manganese steel, 13% Cr steel, clad steel pipe or duplex stainless steel • Corrosion protection on the steel surface made in fusion bonded epoxy instead of coal tar due to the outstanding properties at elevated temperatures. Anti-corrosion coating of a pipe consists to spray epoxy powder onto pipe pre-heated at about 232°C • Insulation material made of syntactic foam (polyurethane or polyethylene) • External coating (polypropylene) to ensure mechanical protection (towards impacts) and sealing (towards the sea water) of foam shells which, when exposed to external hydrostatic pressure, could be filled with water in a longer period of time Pipe

Thermal Insulation Thermal Insulation Pipe

Corrosion Protection Corrosion Protection

Figure 22 - Composition of wet insulated rigid line


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4.7


Pipe in pipe system

Flowline

Outer casing

Thermal Insulation

Flowline

Centralizers

Outer Casing

Thermal Insulation

Figure 23 - Typical pipe in pipe system A typical pipe in pipe system for reel lay (see figure 23) consists of a casing pipe housing an insulated wrap flowline pipe, concentrically positioned in the carrier pipe by means of spacer blocks placed every 2.5m on the production flowline. Insulation material is strapped and attached onto the production flowline pipe using galvanic steel, tape or band wire. The assembly of pipe in pipe consists to pull the production pipe into the outer casing pipe in one continuous length while securing spacer blocks and insulation material on production flowline pipe. A basic pipe in pipe concept applicable for other methods of installation (S-lay, J-lay, Towing) comprises of an inner product carrying pipe inside an outer sleeve pipe. Variations occur when the specific detail of pipe materials, bulkhead configuration, insulation system, field joints or method of fabrication change. The sleeve (or outer) pipe has a multipurpose role in the design of a pipe in pipe system. Keeping the insulating material dry is one of the most basic requirements when designing and installing an insulated subsea pipeline. An obvious solution is to surround the insulation with an external waterproof sleeve (wet insulated system). The use of a sleeve will also protect the insulation material from mechanical damage during installation and service. It reduces the overall thermal loads within the system and can reduce the installation stresses experienced by the system.


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Load transfer can occur between product carrier pipe and sleeve pipe, which results in reduced thermal expansion. This is typically achieved by use of a welded connection (bulkhead) between inner and outer pipe that also provides a high integrity water stop (see figure 24).

8" Oil Line

14" Sleeve

Bulkhead

Preformed Half Foam Shells

14" Sleeve Pipe 8" Oil Line

Sleeve Pipe Half Shells

Solidly Foamed

Figure 24 - Bulkhead assembled between 8-in oil line and 14-in sleeve During the assembly of the pipe in pipe system, the flowline joints are welded together and insulation field joints are applied to fill the gaps at the welds. The sleeve pipes are joined by fillet welding half-shell steel sleeves over the insulation field joints. Preformed half foam shells are top surface fire resistant to prevent from arc burn during welding operation. Preheating may be required for TIG orbital welding process but there is no post weld heating for welded joints of C-Mn steel pipe having nominal wall thickness less than 49mm. The main drawbacks with the use of bulkheads in the pipe in pipe system are numerous cool points along the flowline at every bulkhead locations.


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4.8


Pipeline bundle system

Electrical Umbilical Low Density Foam Insulation Hydraulic/Chimical Lines Elastomer Spacer Methanol Injection Line

Production Flowline

Water Injection

B / CROSS SECTION BETWEEN SPACERS

Insertion Rollers Protective Casing Pipe

A / CROSS SECTION AT SPACER LOCATION

Figure 25 - Pipeline in bundle configuration This configuration is defined as having multiple flowlines, hydraulic control and service lines, and electrical umbilicals encased or integrated in a single carrier pipe or casing (see figure 25). As required electrical or circulating fluid heating lines could be integrated to reduce the risk of hydrate and wax plug formation when production lines are shut down or to heat up the production lines before start up. In the deepwater pipeline bundle configuration, all flowlines are wrapped in two half shells of moulded low density , open-cell polyurethane foam, approximately 2-in thick. This isolates the warm space near the flowlines from the cool annular space in the casing. Hard polyurethane spacers are used to secure all flowlines and umbilicals. Rollers wheels on the spacers facilitate flowline bundle pull-in into the outer casing. There are no intermediate bulkheads isolating the annular space of the casing. The entire annular space is permanently pressurised with nitrogen, in order to maintain zero differential pressure across the casing wall at the deepwater end. This allows the casing to resist collapse while minimising the required casing wall thickness and bundle diameter. An unusual aspect of the bundle is the high casing diameter to thickness (D/t) ratios, which approach 100 for deepwater pipeline configuration. The fabrication of the bundle started with the welding of carrier pipe followed by the pull-in of the internal components as the assembling proceeds. The bundle is fabricated onshore using a relatively inexpensive fabrication spread (compared to an offshore lay vessel), and then is towed to location using a construction spread that may consists of two high bollard pull tugs and a survey vessel. The design of a pipeline bundle to be installed by tow method is considerably more complex than that of a normal submarine pipeline. The design embraces fabrication, installation and operational requirement, and proceeds from the inner pipe outwards to the carrier pipe with iterations of design where necessary.


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Typical design considerations are as follows : • the inner pipeline material and wall thickness are based on normal operating and design conditions and maximum allowable stress, as well as accounting for axial restraint imposed on the pipe by carrier pipe and seabed friction • minimum thickness of PUF insulation is calculated on the allowable temperature drop for a given duration • nearest standard pipe-sizes and wall-thickness is chosen for the carrier pipe to accommodate the required amount of lines and insulated material • the carrier pipe is not subjected to direct effects of product flow, but is stressed by heat transfer through the PUF and by pressure/temperature effects from the inner pipe via the bulkheads placed at defined distance • the carrier pipe is designed to provide adequate buoyancy during towing and requires sufficient wall-thickness to withstand beach-pull, break-out load and towing loads • the bundle’s on bottom stability • the whole bundle is checked to ensure it is capable of withstanding dynamic loads occurring during launch, tow and installation For ultra deep water application (i.e. beyond 1500m WD), there are practical difficulties in the design of the carrier pipe for the tow operation due to: •

carrier pipe D/t ratio optimisation with regard to nitrogen pressure and weight

•

bundle overall net submerged weight for tow operation

Note: On Asgard project, the annulus is filled with inhibited water at ambient pressure after the tow operation.

In this case, the industry is proposing a wet-insulated bundle based on "syntactic foam" with the adequate thickness (e.g. typically in 30" to 32" diameter shell) to provide: •

sufficient buoyancy during towing

•

minimum thickness insulation material

A thinner carrier pipe (e.g. 6mm – 10mm wall thickness) can be retained for the purpose of "wears" during beach-pull (or bottom-tow method), while providing a mechanical containant. Under external hydrostatic pressure, this carrier pipe would collapse in a non controlled manner onto the syntactic foam which is pressure resistant. On completion of towing operation and position confirmed by ROV, the bundle will be connected in diverless mode to the others subsea systems. Please refer to document “Tie-in Methods” – Reference 5 – Deepwater Field development.


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5


INSULATION TECHNIQUES & SUPPLIERS

Deepwater fields are economically developed using subsea completions, with hydrocarbon fluids typically conveyed via multiphase pipelines and flowlines to an existing floating production platform. These flowlines operate in a low ambient temperature, high external pressure environment, conducive to the formation of paraffin deposits or hydrates. The leading strategy to circumvent these deleterious effects is to minimise heat loss from the system using insulation. The proper design of flowline insulation requires a balance among the high cost of the insulation, the intended operability of the system, and the acceptable risk level. Economical long distance production of multiphase wellstream fluids (oil, gas condensate, and water) can be achieved with an effectively insulated flowline by minimising the costs, revenue loss, and risks from the following : 1. Hydrate formation during steady state or transient flowing conditions 2. Paraffin deposit on the inner pipe wall, that can result in flowline obstruction or flow rate reductions 3. Adverse fluid viscosity effects at low temperatures which lead to reduced hydraulic performance or difficulties restarting a cooled system after a short shut-in 4. Additional topside facilities required to heat produced fluids to aid separation processes. The overall heat transfer coefficient (U or U-value) is the parameter normally used to quantify the heat retention characteristics of an insulated flowline. The U-value is directly proportional to the heat transfer radially from the flowline centreline. The U-value can be calculated from the flow behaviour of the production fluid, the thermal properties and geometry of the insulation system, and the ambient environmental conditions. Thermal insulation systems for subsea pipelines are normally designed for an overall heat transfer coefficient U-value (W/m²°C) that aims at preventing a temperature drop below the wax and hydrate formation limits for most of the expected steady state flow regimes. However, transient conditions that frequently may occur at temporary stops or long lasting shut downs, can also predict an U-value giving the operator time to respond before the fluid supercooling reaches critical limits.

5.1

Pipe in pipe system

A pipe in pipe insulation system consists of a single production flowline concentrically positioned inside a protective pipe jacket. Improved insulation can be achieved by filling the annulus space with polymeric foam, silicate microspheres or by establishment of an active vacuum. A pipe-in-pipe system was a logical progress for shallow water offshore insulated flowlines from onshore insulated pipeline experience by employing proven techniques and materials. The attractiveness of pipe-in-pipe flowlines for deepwater is because they are simple to fabricate, use low cost proven materials, and because a high strength protective steel jacket offers nearly unlimited depth capabilities. However, the deepwater versions of these systems can be cost prohibitive for small or marginally economic fields.


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Pipe in pipe systems are well suited for all relevant water depths and provides through a 3-4’’ thick insulation layer, an excellent U-value in the range of 0.8-3.5W/m²°C. Some examples are given in the following table 3: Insulation material description

“U” value

Pipe dimensions (mm)

Microporous material

0.8 W/m2K

Inner pipe = 168.6 (OD) x 11 (Wt)

( k=0.021W/m.K ) Polyurethane foam

Outer pipe = 279.4 (OD) x 18 (Wt) 0.8 W/m2K

Inner pipe = 168.6 (OD) x 11 (Wt)

( k=0.05W/m.K )

Outer pipe = 318.6 (OD) x 15 (Wt) 2

Table 3 – Detailed description of pipe in pipe system with a “U” value = 0.8 W/m K

The higher value is tied to the use of solid polyurethane with a thermal conductivity k=0.19W/m°C (or other high density polymer materials), as needed to improve the pipe collapse pressure and to prevent insulation crushing during installation in deep waters. The insulation material usually used for pipe in pipe are : • conventional polymeric, open-cell foams with low densities (Polyisocyanurate) • high density product consisting of styrofoam spheres in a polymeric matrix (FT600S) The main thermal insulation materials that are normally considered for use with pipe in pipe are detailed below in table 4: Base material

Thermal conductivity (W/m/°K)

Low density polyurethane foam

Density (kg/m3)

0.025

70-500

0.05 - 0.06

250-500

0.85

534

O.01 – 0.022

500

(EMERSON&CUMMINGS) High density polyurethane foam FT6000S Izoflex (INTERPIPE) Table 4 – Thermal insulation material for pipe in pipe system


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5.2


Integrated towed flowline bundle system

Where two or more flowlines, injection lines and electrical cables are connected to the same installation, they may be bundled in a common carrier pipe or outer casing. Bundles are fabricated onshore in lengths up to 16km and are towed to their accurate position, that currently can be as deep as 1000m (Ensearch GC-388 in Gulf of Mexico). Bundled constructions do have the advantage that all flowlines can be accommodated in a common insulation system, which can include additional pipes for heating medium circulation. The carrier pipe is normally pressurised with dry nitrogen, allowing the use of low cost insulation materials such as rock-wool or low density PVC foam shelves with very low kvalues of k=0.04W/m°K. Overall heat transfer coefficient as low as U=0.6W/m²°K can be achieved. The use of heat insulating gel with a k-value of k=0.273 W/m°K can be offset against the more expensive conventional pipe insulation coatings. Gel will also provide adequate ballast for in-place stability, corrosion protection for the flowlines and internal surface of the carrier pipe. The gel is based on mono-ethylene glycol with heteropolysaccharide bio-polymer as a viscosifer and a chelating agent.

5.3

Wet insulation pipe system

Wet insulation systems are flowlines or pipelines that have insulative coatings applied directly to the pipe or corrosion coating. The insulation is not protected by a steel jacket pipe as with either pipe-in-pipe or bundled systems. The essence of a non jacketed insulation is that it must be able to withstand the hydrostatic pressure of the subsea environment, the crushing loads during installation and retain its insulation properties in wet environment for the predicted field life. Wet insulation and corrosion protection systems have been used in the North Sea for more than 15 years and were initially based on the use of bitumen and polyethylene elastomers. Good experience has later encouraged the supplier industry to develop numerous options of solid and foamed polymers/elastomers material that can be tailor-made for most applications and demands in shallow water. For the growing activities in deeper waters (>300m) the options are, however, reduced to the use of solid materials, special engineered polymer composites and epoxy syntactic with hollow glass or silicate microspheres, that can sustain a water depth of more than 1000m and a temperature of 135°C. Such constructions may be supplied with a thickness of 100mm and a k=0.1W/m°K, corresponding to a U-value of 1.5W/m²°K. There are two main concerns with wet insulated pipeline in deepwater applications: - water-logging at high external hydrostatic pressure and thus loosing of its insulating properties (estimated water absorption for syntactic foam at about 10 – 15 %) - required mechanical strength to resist to loads imposed during installation Sometimes pipeline could be coated with different types of insulating layers.


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The main thermal insulation materials that are normally considered for use with wet insulated pipe are detailed below in table 5: Material

Max Water Depth

Thermal conductivity

Density

(m)

(W/m/°K)

(kg/m3)

1800

0.13

830

900 - 1800

0.16

710

Syntactic Polyurethane + Glass beads (BPCL)

1800

0.135

830

Test Syntactic Polyurethane (Joint venture project)

2750

0.1

700

Syntactic Tape (also used for flexible lines)

1000

0.11

640

950 - 1070

0.17

750

1000

0.12

No limit (R&D)

0.16

Syntactic Polyurethane + Glass micro-spheres (ISOTUB, BALMORAL) Syntactic Polypropylene (ISOTUB)

Multi-layer Polypropylene Insulating Elastomer Thermoplastic Rubber

1029

Table 5 – Thermal insulation material for wet insulated pipe

A range of suitable high performance pipeline coatings adapted to spooling processes has been developed. These materials include Fusion Bonded Epoxy (FBE), polyolefines (polyethylene and polypropylene), neoprene and other insulated coatings.


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5.4


Flexible pipe

Insulated flexible pipe used tape wound on the pipe to the necessary thickness to meet the insulation requirement (see figure 26). The tape or flat sheet consists of hollow glass microspheres, in the size range of 100-200 microns, fibreglass macrospheres 0.124-0.5 inches in diameter and an epoxy, polypropylene, or polyester resin binder.

Semi -rigid PVC foam

Figure 26 - A sample of thermally insulated flexible For high temperature application, Coflon watertight sheath placed around the interlocked layer is used as insulation material. This material is capable to withstand temperature up to 145°C. In general there is a limitation on the insulation thickness, due to the sealine “on seabed” stability criteria and “Vault effects” occurred in crushing loads during installation phase. For a 6”-8” ID flexible line, a typical thermal exchange coefficient U of 1.5-2W/m²°K can be achieved with “Carizide” (or Cofoam) insulation material.


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6

HEATING TECHNIQUES

6.1

Introduction

The seabed temperature at 100m water depth and deeper may range from 7°C to -1.5°C, causing a rapid cooling of hot well streams being transported in subsea flowlines. At such low temperature vulnerable crudes and multiphase compositions will deposit wax and asphalt, and the gas - water phase may freeze solid hydrate particles that can permanently block the pipeline. A conventional approach to flow assurance has been to use thermal insulated flowlines in combination with the following measures : • Continuous injection of chemicals to reduce the hydrate freezing point and the rate of wax deposition • Depressurisation of the flowline to enable a further reduction of the hydrate freezing-point • Use of twin parallel flowlines to achieve a more effective depressurisation of pipeline, and to perform pig cleaning operations. Further to circulate hot water/oil in order to melt out wax and to pre-warm the flowlines after long shut downs. It is obvious that these measures do have physical, economical and environmental limitations, especially in deeper waters and over very long transportation distances : • The pressure head in deep water pipelines may give an insufficient pressure relieve at blow downs • Blow down and depressurisation of pipelines will involve pressure drop expansions and a related Joule-Thomson supercooling of multiphase fluids, that by itself can cause severe wax deposits and hydrate formation. • Heat loss in long twin pipelines that shall be preheated in a serial configuration, will restrict adequate heating above 10-15km length • Continuous injection of large amounts of hydrate and wax inhibitors will dissolve in the produced water that may have a restricted release to sea • Long twin flowline installations will generate high investment and operational costs (e.g. OPEX). Thermal insulated and electrically or hot water heated flowlines represent alternative prevention method for wax and hydrates that will not be restricted with the same limitations. A review of different designs and functional principles conclude that electrical heating or hot water circulation heating technologies are available for flexible and rigid pipelines, pipe-inpipe and bundle systems for all practical lengths in subsea transportation. Some of these have been in operation with a satisfactory performance over a period of more than 20 years in shallow water application. Ongoing development and qualification of subsea electrical power distribution systems, is believed to enhance use of electrical powered equipment and in particular heating of subsea flowlines. Heat loss compensation by electrical power or hot fluid (water) circulating system is ensured by providing external heat to the pipe steel material corresponding to a desired temperature Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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equilibrium that may well be higher than the fluid temperature. This operation will heat the fluid to a higher temperature level, and all losses to the sea will be sought from the external energy source. The heating techniques may be designed for the following purposes: -

To maintain steady state pipe temperature above the hydrate formation temperature after planned or non-planned shutdowns,

-

Heating of the pipe, which have been cooled down to the ambient seawater temperature (long shutdown due to equipment failure),

-

To maintain the required temperature at low production rates.


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6.2


Electrical heating system

Electrical energy is well suited for this purpose, as the pipe ferromagnetic properties can easily be utilised to convert electric power to heat. Various alternative conversion principles and alternative methods of how electric power systems can be safely integrated into subsea flowline thermal insulation systems have been developed. Some of these were put into service in shallow waters during the period of 1970 – 80 whereas others are currently being qualified for the future demand of larger transportation lengths and service in deeper waters. Thera are mainly three methods of electrical pipe heating: -

Electric heating cables

-

Electromagnetic induction heating

-

Direct electric heating

The pioneer subsea system and most applied heating principle to date is the SECT system (Skin Effect Current tracing) whereas Combipipe, Combibundles (based on induction heating) and direct electrical heating systems for wet insulation are newcomers on the market place.

6.2.1

SECT Heat tracing

SECT heat tracing may be used and integrated into most of current thermal insulation systems for subsea flowlines. It is characterised by having heating elements consisting of a cable in a magnetic steel tube, where the cables are jointed at each second pipe length (see figure 27). The SECT heat tube and the cable connected together at one end and a source of 50/60Hz AC power is connected between the tube and conductor at the opposite end. A current will then flow from the power source through the conductor and return through the heat tube. This phenomenon is called skin effect, and generates a Joule’s heat that increases with the frequency and voltage level. 80 - 90% of the power supply is generated as heat in the SECT tube and the rest in the cable. In order to achieve a good heat transfer, the SECT tubes are stick-welded to the flowline. Their size may range from ½’’ to 1½’’ with corresponding cables of 5.5 to 60mm 2 and 0.6 to 6.6 kV rating.


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Each heating element (tube) may generate between 15 and 150W/m and has a maximum circuit length of 15km. A typical dimensioning for a 36’’ pipeline is, however, to use five 1’’ tubes in a 5km long 3-phase power system, where 2 tubes are spare, and the other 3 generate up to ~ 40W/m each.

Temperature Indicating Controller

Thermal Insulation Layer

Weld

Production Line Electrical Junction Box

SECT Cable

SECT Tube

Power leading cable

Transformer for SECT Heating System

Control System of SECT Heating Assembly

Figure 27 - General View of SECT System A genuine SECT design under the trading mark TTDPISQ has been developed for pipe-inpipe sections where the inner and outer pipes are coupled through Special Joint Connectors that are butt welded at the ends. The SECT cables are conveyed in the pipe annulus through the connectors and into junction boxes located between the connector (s). Each pipe section may be 12 or 24m long. This solution is well adapted to pipeline in bundle configuration as it is very difficult to implement such technique when installing long pipeline with J-lay, S-lay or reel lay techniques. SECT heat tracing was utilised in Panarctic project in the Canadian High Arctic in 1977 where the SECT cables were integrated in a bundle pipeline.


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6.2.2


Combipipe Induction Heating

Combipipe systems are designed for a simple installation of induction cables into rigid and flexible flowlines wet thermal insulation system (see figure 28). This is achieved by pre-machining or moulding 2 or 3 grooves in the full axial length of the flowline thermal insulation, whereas the cables normally are installed offshore during the flowline lay operations. The cable grooves are typically 30-50mm deep and also comprise a guidance for a flat protection strip at top of the cable, which is strapped in place. The maximum distance from the pipe to the induction cable in deepwater application is limited to 100mm.

Groove

Flat Protection Strip Production line

Induction Cable Flowline Strap Thermal Insulation

Figure 28 - Combipipe heating The embedded cables are at one end connected to a high voltage source of 12kV with a variable frequency control of 50/60-200Hz. The opposite ends of the cables are connected to each other in a prefabricated joint that is integrated in to the pipeline insulation. Coulomb heat is generated in the outer skin of the flowline ferromagnetic material by electromagnetic induction from the high frequency alternative current in the cables. 60-70% of the power supply is generated as heat in the flowline and the rest in the cable. Combipipe heating systems may generate between 50-200W/m and have a maximum circuit length of some 70 km. This distance limitation is mainly due to the difficulty in producing high voltage (more than 36 kV) small cable to compensate the voltage drop in long pipeline.


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6.2.3


Combibundle induction heating

Combibundle will generate heat in the same way as Combipipe, but with the induction cables located inside the thermal insulation of the flowlines (see figure 29) . The cable will thus be installed onshore during the bundle assembly.

Umbilical

Induction Cable

Flowline & Service Lines Induction Cable

Thin Steel/Al Plating Centralizer

Figure 29 - Combibundle Heating A Combibundle heating system does not have any physical limitation with regard to maximum heat generation and electrical circuit lengths as the number of induction cables is only limited to size of the carrier pipe. This solution qualified for a specific installation at a full scale test in 1992 is more expensive and efficient than the SECT heat tracing.


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6.2.4


Direct heating

In direct heating systems the flowline ferromagnetic material is used as a return conductor. Of practical importance for subsea flowline heating, two different AC system arrangements are available for respectively pipe-in-pipe and wet thermal insulation systems. Direct heated pipe-in-pipe is a system arrangement where the flowline is electrically insulated from the outer concentric pipe (see figure 30). The dry end of the flowline and the outer pipe are connected to a suitable single phase AC power source, whereas the opposite ends are electrically junctioned. The electrical current will partly be conducted through the outer pipe and the sea water, but the full current will be returned through the thermally and electrically insulated flowline.

Thermal Insulation

Outer Pipe

Electrical Connector

Cross-section Power Supply

Concrete Protection

Flowline

Figure 30 - Direct heated pipe-in-pipe Coulomb heat will as a function of the pipeline (s) Ohmic resistivity be generated both in the flowline as well as in the outer pipe. No operational data or research results have been obtained for the direct heated pipe-in-pipe system, but it is assumed that approximately one half of supplied power is lost in the uninsulated outer pipe, leaving one half for effective heating of the flowline.


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Direct heated wet thermal insulated flowline is another alternative arrangement for direct heating of wet thermal insulated flowlines, where both phases of the voltage source are connected to each end of the flowline (see figure 31). No external electrical potentials will be exposed towards the flowline ends (platform/subsea production wellheads), as the current will solely pass between the connection points of the feeder cable (s). Flowline

Feeder Cable

Thermal Insulation

Power Supply

Figure 31 - Direct heated wet insulated flowline Conduction of the current will however be divided between the seabed, seawater and the flowline with a ratio that is mainly dependent on the flowline electromagnetic properties and the flowline electrode/anodic system. Furthermore, this system does not impact the pipeline cathodic protection. A carbon steel flowline with an ordinary thermal insulation and Aluminium-sacrificial anode system will, according to test, distribute some 40-60% of supplied current through the flowline steel material, whereas the rest is transferred through the seabed and water. The heating exposure is also dependent on the distance between the flowline and the parallel feeder cable. A full scale subsea test showed that adequate heating in the range of 50-200W/m could safely be achieved, both when the feeder cable was laid 500mm away from an 8’’ pipe, as well as when the feeder cable was clamped as a piggy-back on the 50mm thick thermal insulation. This system has been qualified for the Asgard and Huldra projects. Further expectations are that heating by this method would become available for all actual lengths of flowlines, both as a permanent installation made during pipe lay as well as being possible to install if and when a demand arises. The current limits are due to the cable insulation level (36 kV), fixing the max pipeline length to 50 km.


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6.3


Hot fluid circulation heating system

Review of contractor and supplier technology shows that circulation of hot fluid is probably more reliable at this time for very deepwater applications than electrical heating. Moreover, the geometry of the flowlines suits the circulation of hot fluid which is boosted by the hydrostatic head as the hot fluid is injected from the floater and dumped to sea. This hydrostatic head will increase in deeper waters.

6.3.1

Hot water heated wet insulated pipe

The architecture of the system is designed for a simple installation of hot water lines in piggy back during the offshore installation of subsea flowlines. It consists in installing concentrically hot water lines on the production line by means of wet insulated shelves, which are strapped in place during the flowlines lay operations (see figure 32). Hot water line

Wet insulated shelf Flowline Strap

Figure 32 - Hot water wet insulated pipe The hot water lines are used to flow hot water to heat up the production line. The water is injected from the floating production platform and dumped to sea. By using 2-in hot water lines and circulating hot water at 80°C at the floating production platform, the estimated time to heat up a 10-in production line from 5°C to 30°C over 5000m is 6 hours, which is reasonable.


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6.3.2


Hot water heated bundle / pipe-in-pipe system

This system will generate heat in the same way as above, but with the hot water lines located between the thermally insulated production line and carrier pipe or outer sleeve (see figures 33 and 34)). The hot water lines are held in place by means of insulated centralizers or interlocked devices strapped in place during the onshore assembly of the bundle or pipe-inpipe. This dry insulation with active heating configuration provided very low U-values (down to 0,5 W/m²°k).

Production line

Hot water line

Thermal insulated shelf

Service line Carrier pipe

Control umbilical

Thermal insulation material

Figure 33 - Hot water heated bundle

Hot water line Insulated interlock device

Outer sleeve pipe Production line

Figure 34 - Hot water heated pipe-in-pipe


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6.3.3


Hot water heated flexible

The hot water heated flexible is a system arrangement where the hot water lines ,made in rigid or flexible pipes, are radially placed between the lower and upper intermediate thermoplastic sheath layers of the flexible structure by means of plastic filler (see figure 35).

Hot water line Upper intermediate sheath layer Lower intermediate sheath layer

Production line

Plastic filler

Figure 35 - Hot water heated flexible By using 2-in hot water lines and circulating hot water at 80°C at the floating production platform, the estimated time to heat up a 10-in production line from 5°C to 30°C over 5000m is 6 hours, which is reasonable.


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7

BURIAL TECHNIQUES

7.1

Introduction

Many submarine pipelines have to be trenched. A trench protects the pipe against damage from fishing gear, reduces hydrodynamic forces from waves and currents, gives a degree of protection from small anchors and from construction vessels’ mooring lines, and may be desirable for safety or environmental reasons. The relative importance of these factors naturally varies from project to project. If the trench is backfilled, protection against fishing gear and wave is fully fulfilled, risk due to others damages is reduced, and heat transfer between pipe and the sea is reduced. However in deepwater there is no fishing activity, this explains the fact that most sealines are laid untrenched in current deepwater field development. The requirement for better thermal insulation of the sealines could dictated the sealines to be trenched and backfilled; in transient conditions a trenched sealines could provide a longer shut down time by a factor of 4 when compared to the same untrenched sealine. For the purpose of sealine flow assurance at low seafloor temperature, there is a need to review existing burial or trenching techniques which could be used in deepwater applications. Jetting was the technique almost always used to trench submarine pipelines. Since jetting techniques were first developed in the 1950s, they have been substantially modified, but their efficiency is much affected by geotechnical conditions of the sea bed. In medium clay, for instance, jetting cuts a neat rectangular trench, but in loose sand it leaves a wide and shallow trench, with side slopes less than 10°, which does little to protect the pipeline. In the wrong conditions, jetting is slow and expensive. A creative dissatisfaction with the high cost and limited efficiency of jetting led to a search for better trenching methods. There have been two principal axis of development, ploughs and mechanical cutting systems. Each of these systems is appropriate in the right conditions. At first, mechanical cutting systems (bucket wheels, cutter-heads, ripper wheels) were plagued by mechanical and electrical faults, and by sensitivity to bottom soils and topography. These problems have now been largely overcome and good results have been achieved with cutting systems in a number of project particularly the trenching of power cables in the English Channel. At the same time, there has been a major development of pipeline trenching ploughs which met a hostile and often derisive response in the past. Ploughing is now an accepted and widely used technique, and in many conditions is the method of choice.


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7.2


Plough technique

Ploughs were used to trench pipelines in the UK and the Middle East in the 1960s. With hindsight, it appears that the difficulty of designing a good plough had been underestimated. A plough designed incorrectly either digs too far and becomes anchored, or fails to penetrate and scrapes along the surface without making a proper trench. Moreover, it is sensitive to soil strength, and cuts at different depths in different soils. In all subsequent pipeline trenching operations, the long beam configuration has been adopted based on the following considerations : • The plough was to be pulled by a tug with a bollard pull corresponding to plough weight and soil conditions • Accurate depth control was essential, since otherwise the specified trench depth would not be achieved everywhere, and the plough might require more force than the tug could apply. The outstanding advantage of this configuration is precise and consistent depth control. Skids or wheels hold the front end of the beam at a fixed height above the sea bed. The rear end of the beam carries a share, which cuts the soil and lifts it upwards and sideways (see figure 36). REAR

Twin hinged Half shares

FRONT

Skid

Figure 36 - Single pass plough (long beam configuration) Mouldboards push the spoil outwards, so that it does not fall back into the trench. Under the share, and fixed to it, there is a rigid heel. In normal operation, the plough runs so that the heel is horizontal, and the plough is in balance under the combined action of the soil force on the front of the share, the reaction under the heel, the pull force at the front end of the beam, and its own weight (usually small by comparison with the other three forces. If the plough attitude alters, so that it cuts less deeply, the heel loses contact with the trench bottom, the heel reaction falls to zero, and the share reaction pushes the share downward so that it cuts Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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more deeply. If, on the other hand, the plough cuts too deeply, the heel itself has to cut the soil, and the heel reaction increase and lifts the share to reduce the cutting depth. In consequence of the long beam configuration, the plough cuts at a uniform depth , and the trench does not change if the soil strength changes (unless it becomes so weak that it cannot support the heel or the skids). Pipeline can be trenched in different modes : • Pre-trenching mode consists in cutting a trench into which a pipeline would afterwards be pulled/laid • Post-trenching mode involves the pipeline to be laid first, by a laybarge, a reel or a tow, and then the trench is cut beneath the pipe. In both cases it is required that the trench will not collapse, although this is more critical in a pre-trenching mode, where it may take several days before pipeline installation will take place. In a post-trenching it will only be the few minutes the pipeline requires to settle down. In the post-trenching mode, the principal design problem is to configure the shares so that they can be placed over the pipeline without risk of damage, so that they can close beneath the pipe to excavate a trench under it, and so that the plough can be recovered easily at the end of the operation. The solution to this problem is the ‘’butterfly’’ configuration : twin halfshares are hinged to the rear end of the beam, are placed over the pipe in an open position, and rotate and close under the pipe as the plough is pulled forward (see figure 36). The dimensions of a plough are primarily determined by the depth and cross-section of the trench it has to cut. The structural weight is determined both by the size of the plough and the draft, the pull force required to advance the plough through the bottom soil. The draft increases rapidly with the depth of trench. In clay, for geometrically similar trenches, the draft increases roughly as the square of the trench depth, while for trenches of constant width the draft increase more than linearly with the depth. In sand, the draft increases still more rapidly with trench depth. Consequently any plough that cuts a deep trench in a single pass will necessarily be both large and heavy, and will require a large pull force. Once the pull force exceeds 500 tonnes, the difficulties multiply. Not only does the structural weight of the plough begin to become excessive, but friction generated by the weight itself begins to make a significant contribution to the draft. Because the plough is so heavy, it becomes difficult to handle. A large barge is required to transport it, and a large crane to lower it safely onto the pipeline. There has to be a strong link between the plough and whatever is pulling it : even allowing a rather small factor of safety of 2 on minimum breaking load, a wire rope of some 125 mm in diameter is needed to pull 500 tonnes. Finally the pulling system must be anchored, finding good holding ground, and balancing and controlling mooring line tensions become relatively important if the pull force exceeds 500 tonnes, whereas the requirement to anchor against 100 or 200 tonnes is common and easily satisfied, in deepwater laybarge pipelaying for instance. All these factors indicate that a deep trench should not be cut in a single pass, but that it will be better to adopt a multi-pass technique, in which the required depth is reached in two or more cuts. In this concept, the trench is cut by the front plough to a trapezoidal cross-section, with a level bottom and sides at 30° to the horizontal. In the second pass, a deeper triangle is cut from the bottom of the first-pass trench by the rear plough (see figure 37).


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The burial performance of the multi-pass plough technique is as follows: ♦ Pipe capacity : 500 mm OD maximum size ♦ Trench depth : 0 – 1.8 metres maximum ♦ Operational depth : 500 metres maximum

Second Plough

Fisrt Plough

FRONT

REAR

Skid

Figure 37 - Multi-pass plough When pipeline engineers speak of ‘’burial’’, they generally mean ‘’trenching’’. Trenching techniques usually leave the pipeline in an open trench. Ploughing leaves the spoil neatly piled along the trench sides, rather than dispersed into the water. As well as eliminating water pollution, this has the advantage that once trenching is complete a backfilling device can move along the trench, to push the spoil back to cover the pipeline. A back filler can be constructed on the long beam principle.


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7.3


Jetting technique

All submarine pipeline burying methods require the preparation of a ditch or trench in which the pipe is lowered during the operation or afterwards. Most methods can be applied successfully in sea beds consisting of cohesive soil such as clays. In cases where the sea bed is noncohesive (e.g. sand) the trench will fill up rapidly, resulting in a too small burial depth of the pipeline. For those areas where the sea bottom consists mainly of sand and soft clay, the adequate method involves fluidisation of the bottom adjacent to the pipeline over such a length that the pipeline, having lost its support, sags to the desired depth, aided by its flexibility and the load exerted by the fluidisation device resting on the pipeline. Some pipeline burial vehicles using the jetting technique up to a water depth of 1000m are described hereafter: •

Flexjet from Perry Tritech

•

Capjet from Alcatel Kabel Norge

The Flexjet, a lightweight flexible pipeline burial vehicle was designed based on the above principle. It consists of a 400 HP water jetting system which is electrically and hydraulically controlled by a 100 HP Triton Work Class ROV located in the center of the Flexjet vehicle (see figure 38).

Trenching arm

Jetting pump

Motorised Track

Figure 38 - Flexjet The Flexjet has a set of tracks that are used during burial operations and general bottom crawling. When transiting to the operational area on the seabottom the Flexjet is neutrally buoyant and ‘’flies’’ as a standard ROV. Once on the seabottom the vehicle can be ballasted down by bringing on board 1.5 tonnes of water with the variable ballast system. The 1.5 tonnes ballast load during crawling allows a 1 tonne draw bar pull of the Flexjet. Trenching results are obtained with 400 total HP of jetting power split between high pressure and low pressure jetting systems. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The high pressure jetting system consists of 2 x 125 HP pump/motor sets. The high pressure jet on the trenching arms face forward into the direction of Flexjet travel and are used to cut or fluidise the soil. Each 125 HP assembly produces 6,623 LPM at 8.5 bar. The low pressure clearing jet systems consists of 2 x 75 HP motor/pump assemblies. The low pressure jets on the trenching arms face aft and are used to clear the fluidised soil from the trench as it is fluidised by the high pressure jets. Each 75 HP assembly produces 13,247 LPM at 1.7 bar. Several sets of trenching and backfilling flange mounted arms are available with the Flexjet system. Since 1993 Flexjet has been successfully used for the trenching of telecom/power cable, electrical umbilical, 2’’ to 8’’ flexible flowline, rigid service and injection bundle. The burial performance of the Flexjet is as follows: ♦ Pipe capacity : 400 mm OD maximum size ♦ Trench depth : 0 – 2 metres maximum ♦ Operational depth : 1000 metres maximum The Capjet trenching system, developed for the protection of subsea cables, umbilicals and pipelines, uses the waterjetting principle for both trenching and propulsion thus presents no risk of damage to the subsea lines or structures (see figure 39). Simultaneous backfill with the fluidised materials is achieved during the trenching operation. The Capjet system is an alternative to existing heavy equipment that can cause damage to cables, umbilicals, flexible and rigid pipes, and subsea installations. The cable or pipe does not pass through the Capjet, and the machine can therefore start and stop trenching operations at any point along the route. No forces are applied to the cable, umbilical or pipeline during the operation. The system is neutrally buoyant in water, but can be ballasted during the trenching operation.

Figure 39 – Capjet The Capjet systems are capable of trenching in most clay and sandy soil conditions. The systems are suitable for offshore operations (up to 1000m) and have all modern positioning and data collection equipment. Depending on the soil conditions, a trench depth up to 3m can be achieved by the existing jetting trenchers. Main experience of Capjet system is listed below: Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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♦ -Haltenpipe (1996) 57km 16” rigid steel pipe trenched to 0.6 – 1.2m, ♦ Troll Olge and TOGP projects (1994- 1998) 200km of umbilical and flexible pipe, ♦ Oseberg Ost (1998) 24km 12” rigid steel pipeline trenched to 2m for insulation purpose.

7.4

Mechanical cutter technique

For large size pipelines an alternative to a protection technique can consists in an overdesign of the pipe and coating mechanical characteristics in order to make it capable of taking up possible accidental impact loads. For small size lines, that are power and telecommunication cables, rigid of flexible flowlines or pipelines, flowline bundles, the more convenient protection is to bury them in a properly sized trench ; different methods such as sand bagging or backfilling are often more expensive or may prove hazardous for line safety or may not satisfy required protection standards. A specific surface controlled trenching system conceived for the task of burial small size lines consists of a steel frame which connects the two motorised tracks and support the main subsystems. The vehicle can move on sea bottom by means of large supporting surface hydraulically motorised tracks. The guidance of the vehicle along the line path is obtained by means of an arm which, articulated at the vehicle bow, supports the line on rollers ; such a device, following the line route, gives the locomotion system the proper indications for guidance during trenching (see figures 40 and 41). The trenching system consists of a cutting chain which runs on steel rollers supported by a proper frame. The chain is driven through a reduction gear by a hydraulic high speed motor. The chain-frame system is placed at the center of the vehicle and can rotate in a longitudinal plane in order to reach the selected digging depth ; it can moreover rotate laterally to ease the operations of line installation on the supporting rollers During operations the line to be buried is held above the trench by means of a roller supporting device which is connected to the digging chain frame. The supporting device geometry and roller design guarantee the acceptable line bending and local loads. In case of flexible line burial a conveying device, consisting of a rigid arm hinged at the vehicle stern, guides, by means of rollers, the line itself onto the trench bottom.


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Flexible pipe

Trench

Figure 40 - Mechanical cutting trencher in flexible trenching configuration

Rigid pipe

Trench

Figure 41 - Mechanical cutting trencher in pipe burial configuration The monitoring of the line supporting device geometry and loading allows a real-time knowledge of the mechanical stresses in the line itself and of the burial depth during trenching. In general, a trench depth of 2-3m can be achieved with existing mechanical cutter trenching technique.


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Digging chain Motorised track

Figure 42 - Other type of digging chain trencher

Cutting wheel

Figure 43 - Trencher with cutting wheel


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7.5

Backfilling / Rock dumping

7.5.1

Introduction

The requirements of the authorities for a minimum distance (typically 0.9m) between top of pipe and mean seabed level or fully covered pipe have created the need to develop different backfilling methods in addition to the sandbagging : • To take the material from the seafloor by suction hopper ship dredgers and pumping it through a floating hose to a DP vessel positioned above the pipeline. The material will then be transferred through a vertical fallpipe down to the gas pipeline • To use a converted bulk carrier with a DP system. This vessel utilises material taken from shore and placed above the pipeline through a vertical fallpipe equipped with a guiding thruster at the lower end.

7.5.2

System description

The system based on the use of dredged seafloor material in two layers with fine sand as the first layer and a coarser gravel layer at the top is applicable if these materials are available nearby the pipeline. The spread consists of two trailing suction hopper ship dredgers to dredge the sand and the gravel respectively. A dynamically positioned ship stationed above the pipeline to act as a feeding vessel (see figures 44 and 45). The dredgers are linked to the drill ship by a floating hose and pumped the backfill material to the moonpool of the ship where the material was directed to the trench via a fallpipe assembly. The fallpipe string is made up of steel sections and suspended from the derrick hook. It provided guidance to the backfill material from the feeding vessel to the subsea pipeline. A telescopic-joint is incorporated in the fallpipe string to provide flexibility with respect to depth variations along the pipeline. Navigation of the dump vessel is performed by its DP system. Position references are provided from a combination of bottom acoustic system and surface positioning system. Angle indicators are mounted on the fallpipe giving the distance of the discharge head to the feeding vessel reference point. During unloading of the hopper dredgers, the material is sucked out of the holds using dredging pumps. The water and gravel/sand mixture is pumped through a connection pipe, quick release-coupling and floating hose to the feeding vessel. The dredger takes position towards the feeding vessel in such a way that the 400 m long floating hose is protected as well as possible against the influence of wind, waves and current. For keeping their position, the dredgers used the bow thrusters and twin screw propulsion. For surveying, a sub-bottom profiler is mounted on the lower end of the fallpipe. This made it possible to locate the pipeline during conditions of poor visibility and it was also used as a back-up for the navigation system.


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Figure 44 - Feeding vessel

Figure 45 - Trailing suction hopper dredger


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Figure 46 - Deep sea dredger (R & D) The deepsea dredger as illustrated in figure 46 has been developed for the mechanical backfilling of deepwater pipeline up to 1000m water depth. In this concept, the backfill material (if available) is dredged directly on location nearby the pipeline then directed to the pipeline. Thus, the pumping of backfill material to surface and the discharge through fallpipe are avoided in this efficient and cost effective solution. The other system is based on a converted bulkcarrier doing the backfilling operation as well as transporting the backfilling material stored in several holds from shore to the location (see figure 47). The vessel is equipped with retractable azimuth thrusters for the DP system. The primary navigation equipment for position keeping is interfaced to the DP system and consisted of three different positioning systems. These systems have fixed radio beacons on the platforms in the area or use satellite navigation system DGPS. In addition the equipment could utilise an acoustic underwater navigation system based on transponder located on the seabed. The vessel uses any of these position keeping systems or a suitable combination. The accuracy of the primary navigation systems enabled the DP equipment to hold the vessel stationary within 2 to 3 meters of a desired position. The system also enabled the vessel to automatically follow a predetermined track at a constant speed varied according to the need. Once the vessel is on location, a fallpipe made of polyethylene is lowered through a Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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moonpool. At the lower end of the fallpipe is an electro-hydraulically driven thruster unit. The thruster unit consisted of three propellers located tangentially to the fallpipe at 120° to each other. This enables the operator to move the thruster and the fallpipe in any direction. The thruster unit is equipped with an underwater navigation system based on acoustic instruments which enables the operator on the vessel to ‘’see’’ the exposed or buried pipeline and the sea bottom profile. This system consists of two sub-bottom profile arrays containing transducers, a scanning profiler with transducers and miscellaneous auxiliary equipment such as TV cameras, lights, etc. By means of the acoustic reference system the position of the thruster unit could be accurately determined in relation to the vessel or in relation to marker transponders on the bottom. The thruster operator on the vessel could then, by means of the underwater navigation system, position the end of the fallpipe directly above the pipeline and move it in a pattern which ensured correct placement of the backfilled material. In each of the cargo holds there is an excavator mounted on a pedestal. From each hold, there is a belt conveyor which transported the backfill material to a collecting conveyor, taking the backfill material to the hopper above the moonpool from where it is conducted through the fallpipe to the seafloor. In the moonpool hopper, water is added to the backfill material in order to compensate for the displaced water when the backfill material fell through the fallpipe.

Figure 47 - Flexible fall pipe vessel in rock dumping operation


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7.5.3


Pre-lay pipeline support

The installation of pipelines over highly irregular seabed requires a pre-lay gravel support to prevent excessive free-spans and overstressing of the pipelines (see figure 48). These gravel supports with heights up to 12 m and sides slopes of 1:2 to 1:3 were accurately placed in water depths down to 1000 m. Installation tolerances were +/- 1 m horizontally and +/- 0.15 m in height.

Figure 48 - Pre- lay pipeline support


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8

INSTALLATION TECHNIQUES

8.1

Introduction

The choice of installation methods is considered to be project specific ; at this time, there is a cost incentive to extend the use of conventional S-lay vessels into deep water. In very deep water, however, S-lay may not be technically and economically possible, and the installation option is limited to the J-lay method. Towing the system can also be considered for limited length pipelines. Reeling methods are limited by pipe diameter, either due to strain limitation during reeling or by the maximum pipeline length which can be installed in one operation. For installation of large diameter pipelines in very deep water, the J-lay and towing methods are potentially the most attractive. However in 1996 to the surprised of the laying industry, the Dutch company Allseas has completed the 12” flowline laying for Shell Mensa at 1620m, from the DP Lorelay vessel. Allseas has innovated with a variation of the S-lay technique known as Steep S-Lay and have recently completed the installation of the deepest sealine of 12” Marlim (GoM) export line in 1650m water depth. In the Steep S-Lay technique, a shorter stinger (e.g. 80m long) with a smaller radius of curvature is being used, to reduce the pipeline departure angle closed to the J-Lay method. With improved weld quality control and management of the Steep S-Lay ramp, a medium diameter pipeline can be laid at a strain value of 0.4%. This strain value requires a radius of curvature of 40m for a 12” pipeline and 50m for a 16” pipeline with the necessary tension no greater than J-Lay. At report date, there are only few lay vessels to be equipped for the Steep S-lay technique: •

Allseas Lorelay and Solitaire DP vessel

•

Global Chickasaw and Hercules DP barge

However newcomers shall be expected e.g. ETPM, EMC.


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8.2


S- lay method

Most pipelines are constructed by the laybarge method, and most pipelay barges carry out pipelaying in the S-lay mode, see figure 49. Lay Ship

Sea Level

Stinger

Rigid Pipe

Seabed

Figure 49 - S-lay configuration This technique consists in installing offshore pipeline with the pipe axis in the horizontal position (5G) on the lay barge. The lay barge typically has a serie of tensioners to hold the pipe into a ‘S’ bend. The near horizontal ramp allows space for several welding stations, an X-ray station and a field joint station, tensioners, and a stinger of acceptable length can be combined with an acceptable tension level. A very long stinger is undesirable, because it is excessively vulnerable to wave and current forces. High tension is undesirable, because of the risk of damage to the pipe coating caused by the tensioner and because the tension has to be balanced by the barge’s mooring or dynamic positioning system. S-lay was applied to lay the vast majority of pipelines in the world and this technology was believed not suitable for ‘’deep’’ water. The maximum effective depth for S-lay is dependent on the pipe diameter and lay vessel characteristics. Some examples of laying parameters are provided in the following table 6: Lay depth

Steel pipe dimensions

Subm. weight

Eff. mass

Hor. force

150m

OD 406mm, wt 15.9mm (concrete coating wt 63.5mm)

121.57 kg/m

582 kg/m

333 kN

237m

OD 508mm, wt 23.8mm

84.366 kg/m

501.5 kg/m

279 kN

Table 6 – Examples of laying parameters


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8.3


J-lay method

Figure 50 - J- lay configuration It has been recognised for a long time that J-lay has significant advantages, particularly in deep water. It eliminates the vulnerable stinger, or at least allows it to be very short, and allows tension to be substantially reduced. Furthermore it allows more flexibility in terms of pipeline route. The J-lay technique places the pipe axis in the vertical position (2G) on the lay barge with a continuous radius to the sea bottom (see figure 50). Generally, this technique reduces the tension required (less strain in the pipeline) and makes it possible for much smaller vessel to perform the pipelay operation. The major limitation of the J-lay technique is the number of working stations. A conventional lay barge will have 5 to 10 working stations. The work of welding, inspection, repair, and field coating is divided over these stations to maximise production. In the case of J-lay construction all these functions must be performed in one station making the cycle time of adding one pipe length much longer than on a conventional barge. Moreover, the obvious disadvantage is that the steep ramp means that if welding operations are carried out at a number of separate stations, line-up and first welding stations are at the upper end of the ramp, high above water level. That has major implications for the layout of the vessel, as well as for its stability and resistance to rolling in a seaway. If, however, welding operations can be carried out at a single station not far above the waterline, then J-lay becomes attractive. A pipe transfer system elevates pipe strings (e.g. 72m sixjoints or 48m quadruple-joints) which had been welded together offshore or onshore and brought out by cargo barge. Most of the proponents of J-lay have focused on its applications in very deep water. However, there is no reason to confine the method to deep water, and it has advantages in intermediate depths. If these technical advantages can be realised as commercial advantages, J-lay can be competitive in projects conventially thought of as the preserve of S-lay. It may be necessary to reduce the ramp angle, as is routinely done in reelship pipelaying (see figure 51).


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Figure 51 - J-Lay System. Variable angle ramp for shallow and deep water Note: The laying angle is dependent on the water depth, laying tension and vessel RAO.

Because the pipelay is without residual strain, most pipelay contractor have invested in the JLay method: •

Heerema balder DP semi-submersible with a 2 x 6 strings J-Lay tower (Shell New Zealand 20” Clad pipe in 110m WD)

•

Mc Dermott DB 50 with a 4 string J-Lay tower (Shell Auger TLP 2 x 12” oil and gas export line in 870m WD) (Shell Mars TLP 14” oil and gas export line in 950m WD)

•

MSV Amethyst with a 2 strings J-Lay tower (Petrobras Marlim 10” gas export line from P26 to P18 semi-submersibles in 910m water depth)

•

Seaway Falcon with a reverse bend J-Lay system

•

Saibos FDS with a 4 strings J-Lay tower (under construction)

•

Saipem 7000 with a 2 x 4 strings J-Lay tower


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J-Curve laying tension parameters for pipeline with D/t = 20 in 915m water depth are presented in the following table 7:

PIPE DIAMETER

TENSION (T)

(inches)

EMPTY

FLOODED

8.6250

99

231

10.750

143

352

12.750

165

462

14.000

198

572

16.000

242

726

20.000

528

1254

24.000

715

1738

Table 7 – J lay tension parameters for different pipe sizes


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8.4


Reel-lay method

Though reelship pipelaying is not generally thought of as J-laying, it is in reality identical as far as the mechanical behaviour of the suspended span is concerned (see figure 52). The reelship takes advantage of the low tension that J-lay allows : this is particularly useful because the reelship is dynamically positioned. The reelship method had been developed in parallel with the S-laybarge method. The original idea can be traced back to the PLUTO project which laid 3-inch products pipelines across the English Channel in 1944, from floating reels towed behind tugs, but the technology implemented in the reelship is much more sophisticated and controlled. The pipe is wound onto a vertical plane - horizontal axis reel with a 16.3m hub diameter and the ability to carry 2000 tonnes of pipe. Pipe is paid out onto the reel from a ramp, with an aligner at its highest point which also serves as a level wind. The pipe leaves the reelship through the aligner, then through a straightener and tensioner (s) and down an adjustable steep ramp into the water. A pipe clamp is located at the foot of the ramp. In the actual reelship concept, the maximum diameter that can be handled is 16 inches.

Figure 52 - Reel-lay configuration This technique requires an onshore welding yard to prepare long strings (e.g. 500m) which will be later joined together during the reeling process onto the lay vessel. During the reeling process at quay-side and the subsequent unreeling offshore, the pipeline will experienced plastic deformation and cumulative strain deformation which are to be maintained within acceptable criterias. There are less reel-lay vessels when compared to J-Lay vessels; with Coflexip Stena Offshore leading the way in deepwater laying generations: •

CSO Apache 2000Te reel capability with a 1998 world record 12” gas pipeline in more than 1300m of water depth in the Itapemerin Canyon offshore Brazil

•

CSO Kitt new 5000Te reel lay capability to be available early year 2000

•

ETPM Norlift 1250Te reel capability

•

DSND Nordica 1500Te reel capability


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8.5


Tow method

Pipelines can also be installed in deep water by tow techniques (see figure 53). Bottom tow sets the pipe on the bottom through the entire tow, and does not need a separate lowering operation. Mid-depth tow transports the pipe at a relatively shallow depth, and the pipe then has to be lowered into place, either by controlled lowering or by pull-down. The surface tow method is not commonly used because of the influence of surface waves and currents on the bundle. It is bent by currents and develop dynamic stresses under wave actions. Waveinduced cyclic stresses may cause fatigue damage in the bundle. The waves also create dynamic forces in he bands which connect the pipe and the floater. The bottom and middepth tow operations become more complicated as the installation depth is increased, but remain feasible at great depths. In principle the tow technique involves the transportation of a bundle suspended between two tugs, the Leading Tug and the Trailing Tug.. To maintain control during tow, the bundle is designed and constructed within specific tolerances with respect to its submerged weight.

Figure 53 - Controlled depth tow method Current limits on bundle length are approximately 7km using Controlled Depth Tow Method, and 20 km for Bottom Tow. These limitations are set by bundle size and bollard load of towing equipment. Further innovations are now under planning, including installation in water depths down to 1800m and mid-line tie-ins to allow unlimited lengths. The tow speed is typically lower than 3 knots for a bottom tow method, and in the range of 4 – 5 knots for a controlled depth tow method. The controlled depth tow method has been used mainly in the North Sea (e.g. Shell Gannet, Statoil Asgaard, etc.) while the bottom tow is the preferred solution for the Gulf of Mexico application (e.g. Placid green canyon, BP Troïka, etc.)


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The recognised specialists for the tow method are:

8.6

•

Rockwater (Brown & Root) for controlled depth tow

•

Smit Costain for controlled depth tow

•

Kvaener/RJ Brown/Doris for bottom tow

Flexible Laying Method

Flexible laying operations in deep waters required the mobilisation of a Vertical Laying Spread (VLS) onboard the lay vessel (see figure 54). This spread, a Coflexible Stena Offshore patented system, is specially designed to install large diameter up to 16-inch flexible flowlines in deep waters.

Figure 54 – Vertical flexible lay configuration It is composed of a gutter, which limits the radius of curvature of the pipe entering the derrick, several sets of tensioners inside the derrick and a working table. Depending on its load tension capacity, it can lay flexibles from 2.5’’ up to 16’’ internal diameter over 2000m water depth. Pipeline sections, stored on dolly base reels or carousel, can be passed through the system and connected at the working table below the VLS derrick. The opening of the table when completely retracted allows the lowering of modules up to 3 x 3m size (e.g. Plem, Pig launcher, etc.). This has been particularly developed for connections of second extremities, in which the catenary of the line is suspended to the table, and connected to the hub which is then lowered on the sea bottom and connected onto the subsea equipment. The operations of lowering, abandonment or recovery are carried out with the A&R winch or the pipe follower, a Coflexip Stena Offshore patented technique, which consists in replacing the classical abandonment steel cable by a flexible pipeline. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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Rigid steel pipelines can be also recovered from the sea bottom with the A&R system in order to connect a flexible line (e.g. riser) or, in case of damage, to weld an intermediate device and carry out a repair. The load cases of standard flexible lines in a 1600T basket storage carousel are presented in the hereunder table 8: Inside diameter (in)

Outside Weight in diameter air empty (mm) (kg/m)

Maximum length (m)

Total product weight (T)

Filling rate (%)

2

101

26.1

61000

1600

44

4

164

57.5

27500

"

54

6

227

104.3

15300

"

58

8

286

144

11000

"

68

10

346

195.4

8000

"

75

12

405

249.7

6400

"

77

14

470

316

5000

"

90

16

526

374.5

4000

1500

100

Table 8 – 1600T basket storage carousel load cases Note : 1600T basket storage carousel dimensions:

y Outside diameter: y Inside diameter: y Maximum product height:

17m 4m 7m

The following lay vessels have the capability to lay flexible flowlines with a vertical laying spread: CSO Flexinstaller (at 500m WD)

Seaway Falcon (at 500m WD)

CSO Wellservicer (at 500m WD)

SAIBOS FDS (at 2500m WD) available 3 year quarter 2000

CSO Flexservice I (at 1000m WD)

CSO Kitt (at 2500m WD) available 1 year quarter 2000

CSO Sunrise (at 2000m WD)

Rockwater GSV (at 500m WD)


rd

st

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9

INTERNAL CORROSION MONITORING

9.1

Introduction

Protection pipelines from corrosion is achieved externally by use of cathodic protection (for buried or subsea pipelines) and internally by injection of inhibitors to mitigate internal corrosion. Various inspection and monitoring techniques monitor both a pipeline’s condition for early warning of failure and the efficiency of any mitigation program to reduce or arrest corrosion. While traditional NDT techniques and in-line inspection tools (intelligent ‘’pigs’’) may represent effective solutions for assessment of the condition and integrity of a pipeline, the sensitivity and accuracy of these methods may be inadequate for monitoring inhibitor performance. In this latter case, both the sensitivity and frequency of data collection must be high regularly to produce reliable trends. Even more important to the pipeline operator may be the economics of an inspection and monitoring program. Suitable design of an NDT inspection and corrosion monitoring program may help reduce the expenditures considerably. A combination of monitoring of an actual pipeline with a certain number of Field Signature Method (FSM) stations along a line combined with running smart pigs through the line at infrequent intervals may represent an optimum solution in terms of condition and integrity monitoring of the pipeline. At the same time, such a program may be designed substantially to reduce the costs for inspection as a result of the reduced frequency required of smart pigging.


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9.2


Principle

When a structure is in a known condition, reference FS (Field Signature) measurements are made by feeding an electric current into the structure between two feeding studs. The current spreads out into a pattern which is determined by the geometry of the structure and the conductivity of the material. Any flaws or defects in the structure, like a corrosion pit or a crack will cause a distortion in the electrical field pattern. Also general corrosion, causing a reduction in the wall thickness will result in an increased voltage drop and change in the electrical field. By measuring this electrical field pattern and changes over a period of time, an accurate assessment can be made of actual corrosion, of corrosion rates and trends and the location and severity of pits and cracks (see figure 55). Small sensing pins or electrodes are distributed in an array over the monitored area, to detect changes in the electrical field pattern. A voltage measurement between any two selected electrodes is compared to a measurement between a reference pair of electrodes (for compensation of temperature and current fluctuations) and to the corresponding initial FS values when monitoring started.

3. Corrosion distorts ideal pattern

1. Ideal field pattern

2. Pipe equipped with sensors

Figure 55 - Field Signature Method principle


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9.3


Arrangement of sensing pins

When designing an NDT or inspection program, the inspection engineer will select critical locations of a structure where the risks of corrosion, erosion or cracking are high , or serious hazards might arise in the event of failure. Typical areas chosen for monitoring are : • Girth welds of pipes and pipelines • Bottom sections, e.g. at 4-8 o’clock position in horizontal pipes where corrosive water may be deposited (see figure 56) • Combinations of the above, and area subject to corrosion induced by CO2, H2S or biological activity • T-joints of pipes where there is a risk for erosion/corrosion • Pipe bends and welds (see figure 57)

Figure 56 - FSM applied to subsea pipeline

Figure 57 - FSM applied to subsea production template


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The selected area is fitted with the current induction transformer and the minimum number of 24 sensing pins. This number must however, be increased in multiples of 8 up to a maximum of 64 pins for one FSM spool and instrumentation module. The sensing pins may be distributed in a matrix over the critical area where the matrix spacing or pin-to-pin distance may vary typically from 2-3 cm (1inch) up to 10-15 cm (4-6 inches), depending on the sensitivity required for detection of smaller pits. With a matrix spacing of 2-3 cm the system has a proven capability of detecting and monitoring the growth of pits in welds as small as 1-2 mm in diameter and depth. A matrix spacing of 10-15 cm is used in the case of uniform corrosion, or when wide and shallow pitting is expected. Typical surface area covered per instrumented module may range from 0.1 to 1.1 m2.

9.4

Monitoring system

Permanent instrumentation systems for on-line monitoring are based on FSM stations to be fitted locally, one at each location, and connected via a field bus system to a Master unit in a control room. The Master unit can handle up to 15 FSM stations, and is controlled by an online monitoring software installed on a standard PC (see figure 58).

Figure 58 - Online FSM system based on field bus For subsea and remote monitoring, the FSM system can be supplied as ready made spools for subsea production systems or pipelines. The subsea system consists of the following components (see figure 59): • Instrumented pipe section with sensing electrodes, current feeding arrangement, reference electrodes and subsea matable connector for the instrument unit • ROV replaceable instrument unit contains all electronics and batteries for many years of unattended operation. The instrument unit is hooked up to the instrumented pipe section via the subsea connector. Data communication alternatives are direct cabling or hydro-acoustic telemetry • Top-side data collection and storage unit, including the FSM software package.


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ROV

ROV retrievable instrument unit

FSM Station

Subsea connector Com. connector Pipeline

Figure 59 - FSM system in subsea remote monitoring


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10

APPLICATIONS & LIMITATIONS

10.1

Sealine technology

Pipelines constitute a significant part of costs for field developments. From an economic point of view application of C-Mn steel pipelines is desirable. Such pipelines are, however, vulnerable to corrosion. Selection of C-Mn steel for multiphase pipelines implies that extensive evaluations of corrosivity and inhibitor performance have to be carried out. More accurate models for prediction of corrosion rates have contributed to extended use of C-Mn steel pipelines while change to more environmentally friendly and less effective corrosion inhibitors has the opposite effect. For those fields where C-Mn steel cannot be used due to high corrosivity of the transported fluid, flexible, clad pipe, lined pipe or stainless steel pipelines have to be used. The cost penalty by using such pipelines is presently quite high and for marginal fields it can contribute to restrict field development. By applying new welding methods and technology it is possible to reduce the costs for stainless steel pipelines. This new technology makes it possible to weld duplex stainless steels with the same rate as C-Mn steel. Methods for welding 13% Cr stainless steels which is significantly cheaper than duplex stainless steel are under development. High CO2 contents in aqueous liquids cause rapid weight loss type corrosion and the corrosion loss is increased as service temperature is high. The Cr content of the alloy is essential to improve the corrosion resistance in CO2 or CO2-Cl environments. Therefore, 13%Cr martensite stainless steel and 22%Cr and 25%Cr duplex stainless steel will be selected for use in such environment. The duplex stainless steel can be used for higher temperature service because of their higher Cr content. The presence of H2S causes sulphide stress corrosion cracking in martensite stainless steel and duplex stainless steel. Another effect of H2S is to exacerbate chloride stress corrosion cracking (SCC) at high temperatures. On the contrary, High Ni alloys are generally characterised by good corrosion resistance in non-oxidising acids and SCC resistance in Cl containing solutions at high temperatures. Commonly used austenite stainless steel such as 304L or 316L showed SCC under the condition of 0.1atm H2S, while duplex stainless steels and high Ni alloys showed no corrosion. An increase of partial pressure of H2S up to 1atm makes the environments more aggressive, which resulted in occurrence of SCC in duplex stainless steels. High Ni alloys showed neither corrosion nor cracking even in this condition. These results indicate that higher Ni alloy is preferable for use in H2S-CO2-Cl environment and 42%Ni alloy is one of the most promising materials. The purpose of flexible lines has changed from flexible lines for drilling operation (kill and choke lines) to production lines. In a general view, the structural layers (carcass, pressure armours and tensile armours) were strengthened with thicker wires and different profiles ; some anti-wear layers were added to prevent friction between metallic layers and a fabric layer was also added for a better constraint of tensile armours in order to prevent ‘’bird cages’’ at empty lines submitted to high external pressures. Flexible lines were intensively used for the exploitation of marginal fields in deep waters. The use of flexible pipelines allowed for rapid development of new fields, and the ability to recover and re-use flexible lines reduced their capital cost. Flexible pipes allow rather sharp turn to avoid mooring line interference whereas it would be impossible to accommodate the tight bends in the flowline route using steel pipe. The use of flexible pipe also provided the needed flexibility to modify and adapt the flowline route to accommodate changes in well locations, even at the advanced stages of the project. Throughout the project, well locations were being updated to reflect the results of the drilling and reservoir appraisal, which resulted in changes in flowline and umbilical lengths. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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An attractive alternative to the use of flexible pipe flowlines is the use of rigid pipe flowlines. This is especially true in deep water giant fields or marginal fields, where the distance from floating production units to the wells is often several kilometres. As the flowline length increases the cost effectiveness of flexible pipelines is reduced when compared to rigid pipelines. The choice of flowline for a given deepwater project is a complex topic, where both technical and economical “life of field cost” issues are to be thoroughly evaluated. There is no universal resistance steel and each steel has a particular application domain, which has to be well known to avoid costly mistakes. The following table 8 will summarise the above information:

PIPELINE TYPE FLEXIBLE PIPE

ENVIRONMENT

MATERIAL

* MOST CASES

304L

* HIGH TEMPERATURE (100°C)

316L

* HIGH CO2 & H2S CONTENT

STEEL PIPE

* HIGH TEMPERATURE (130° ) * HIGH CO2 & H2S CONTENT

DUPLEX STEEL

STAINLESS

* HIGH CO2 CONTENT

- 13%Cr

* CO2-CL CONTENT

- 22%Cr or 25%Cr DUPLEX S.S.

* HIGH CO2 CONTENT

- 22%Cr or 25%Cr

* CO2-CL CONTENT * HIGH TEMPERATURE

DUPLEX S.S.

* H2S – CO2 – CL

- DUPLEX S. S.

* at 0.1atm H2S

- HIGH Ni ALLOY

* H2S – CO2 – CL

- HIGH Ni ALLOY

* at 1atm H2S

( INCOLOY )

Table 8 – Material selection

Each flowline material (i.e. C-Mn steel or stainless steel) and technologies (i.e. wet insulated pipe, flexible pipe, bundle, etc.) have their own merits and limitations, as further detailed in the hereafter chapter 11.


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10.2


Installation techniques

The following table 9 will summarised the limitations of each sealine technologies versus the installation techniques : INSTALLATION METHOD AND LIMITATIONS SEALINES

S-Lay (Steep)

1. Wet Insulated Pipe •

Medium size flowline

•

Residual plastic deformation at stinger departure

•

Water depth limitation

J-Lay

Reel-Lay

Tow

•

•

Medium size flowline with D/t ratio within 16-24 for reelability

•

•

Cumulative strain deformation

•

Water depth limitation

No known limitation besides the lay rate

(e.g. 2000m)

Not recommended

(e.g. 2500m)

2. Flexible pipe

•

Not applicable

•

Not Flexible flowline • recommended can be reeled and lay with the ramp tensioners

•

Could be defined as vertical lay

•

Limitation is • Limitation on related to the product flexible technology technology

3. Clad pipe

•

Same limitation as for 1.above (see note)

•

No known limitation besides the lay rate

•

Not recommended

•

4. Pipe-in-pipe

•

Same limitation as for 1.above

•

Will require bulkheads

•

•

Lay rate

Larger carrier Bulkheads to be • pipe replaced by spacers for reelability

•

Same limitation as for 1. above

Not recommended

5. Bundle with dry carrier

•

Not recommended

•

Only for piggyback bundle to main flowline

•


•

Water depth limitation (1000m1500m)

6. Bundle with wet carrier

•

Not recommended

•


•


•

No known limitation for bottom tow

•

Lay rate

•

Lay rate

Table 9 – Installation methods and limitation versus sealine technology Note: At report date, Allseas Solitaire DP Vessel has been awarded the Shell Malampaya pipelay which includes a 16” diameter carbon steel incoloy 825 clad pipe at 850m WD.


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11


ADVANTAGES & DISADVANTAGES

Solid pipes made in C-Mn steel, 13%Cr steel, or duplex stainless steels, pipe-in-pipe or bundle configurations, or flexible pipes are possible alternatives for pipelines. Advantages and disadvantages of different types of pipelines are given hereafter.

11.1

C-Mn steel pipe

The most popular measure to prevent a pipeline from corrosion is the use of inhibitors which form a protective film on the inner surface of the pipe. It is necessary to continuously throw in the proper inhibitor in the proper amount. Mishandling of inhibitors may cause upset of sweetening units or dehydrators. Wall shear stress is a main parameter limiting the application of corrosion inhibitors. The maximum acceptable wall shear stress and, thus, maximum flow rate, depends on the inhibitor used and the geometry. The maximum acceptable flow rate will be higher in a smooth section than in flow restriction. Today’s green (environmentally friendly) inhibitors generally have lower film strength than the more toxic ones which may restrict application of C-Mn pipelines. Pipelines carrying wet gas with condensed water are generally difficult to corrosion protect due to low pH of the unbuffered water. Research on the influence of pH on corrosivity has shown that the corrosivity is decreased by increasing the pH to above 6 by using such as bicarbonate. By doing this the general corrosion rate became lower, but the steel suffered from pitting corrosion. Another disadvantage by using buffers is that the efficiency of the pH stabiliser to prevent corrosion is reduced below 50°C. Application of buffers alone is thus not recommended. Combination of moderate buffering and corrosion inhibitors seems on the other hand to be very effective. Internal corrosion control of wet gas pipelines with this method can extend the application limits of C-Mn steel pipelines. It must, however, be born in mind that buffers cannot be used in pipelines with formation waters since they can lead to scaling deposition. Plastic coated pipes are widely used. Their coated surface is soft and must be carefully handled, and welding of pipe joints is especially difficult. Plastic coated pipes have an additional problem of durability because of loss due to abrasion by rapid flow velocity. 11.2

Flexible pipe

One of the main advantages of the flexible lines is the ability to recover and relay used flexible lines in new projects. The used lines are recovered from the sea bottom, transported to onshore base and submitted to this procedure to assure a safe and efficient utilisation : • visual inspection • internal cleaning • outer sheath repair or new endfittings installation • redefinition of the class of application • hydrostatic test The cost/benefit relation of this procedure is very impressive. The main reason for this is low installation costs. In order to compare the life costs of flexible and rigid pipelines it must be possible to carry out lifetime prediction for rigid as well as flexible pipelines. Presently the knowledge on lifetime prediction for flexible pipes is insufficient. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The pressure and tensile armour are encapsulated between an outer and an inner polymer barrier, and one may believe that the armour wires remain unaffected by both the sea water and the fluid carried in the pipe as long as the polymer barriers are intact. Polymers are, however, open to diffusion of gases such as CH4, CO2, H2S and water vapour. Diffusion of water and corrosive gases into the annulus means that the armour wires are exposed to a corrosive environment. It is well known that the fatigue properties of metallic materials become poorer in corrosive environments. Fatigue testing of wires in corrosive CO2/water environments has clearly shown the number of cycles to failure is significantly reduced in the corrosive environment compared to non-corrosive conditions. Lifetime estimation of flexible pipes should therefore include the effect of corrosion fatigue. It may be necessary to design flexible pipes in such a way that this failure mechanism is avoided. Ageing properties of polymers for flexible pipes are also extensively investigated. Two years testing of PA 11, PVDF and PEX at 400 bar and 90°C in methane/oil/water show that PA 11 exposed to water become brittle, while PVDF and PEX are nearly unaffected. Polymers such as PA 11 and PVDF contain 12-15% plasticiser. During service the plasticiser will leak out and the polymer will shrink. PEX, on the other hand, will swell. The consequences of this also have to be investigated.

11.3

Duplex stainless steel pipe

Duplex stainless steel has been used successfully for completion of highly corrosive wells. The corrosion resistance and mechanical properties make it attractive for highly corrosive pipelines. The advantages of using corrosion resistant alloy instead of C-Mn steel are that corrosion monitoring, intelligent pigging and uncertainties connected to inhibition are avoided and the risk for leakage and oil spill is reduced. The wall thickness can be reduced since the tensile strength is higher than C-Mn steel, and no corrosion allowance is required. Stainless steel is the most economical and effective solution against general corrosion and thus is widely used. In the use of stainless steel, care must be taken as to weldability, stress corrosion cracking (SCC), and the precipitation of chromium carbide which causes intergranular corrosion called ‘’weld decay’’. The biggest problem in the use of the corrosion resistant alloys such as brass, bronze, stainless steel, Monel, Titanium, etc., is high cost as they contain energy consuming such as Cu, Cr, Ni and Titanium. The common factors which play a role in determining the particular economic benefit of using duplex stainless steels are listed below : • the high yield strength of the material (typically 450Mpa for 22%Cr and 550Mpa for 25%Cr duplex in the annealed condition) which allows thinner walls whilst retaining the sample pressure-containing or load bearing capability • the high resistance to corrosion in the internal environment such that, unlike carbon steel, it is not necessary to add a corrosion allowance to the wall • thinner walls which result in reduced fabrication times and reduced weight • the high corrosion resistance which means that it is not necessary to have chemicals to inhibit corrosion, thus reducing the operating costs • the high predictability of the performance of the material such that inspection requirements are minimal and maintenance and unscheduled shut-downs negligible.


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Clad steel pipe

Clad steel pipe is also being tried as a possible solution to the above economic problem. This is a reliable and effective measure both in corrosion resistance and strength. There are several methods to clad materials, such as hot-roll, over-lay welding, explosion, etc., but all these methods require special costly techniques especially in the preparation of joined surfaces, and it is difficult to obtain a completely bonded surface. Further, the tensile residual stress in the clad layer which is generated in the cladding process may be a cause of stress corrosion cracking.

11.5

Bundle system

A key advantage of the bundle concept is the ability to use very effective (low k-value), low cost insulation materials in the annulus of the bundle. Another advantage is the ability to incorporate subsea manifold or even a subsea template in a towhead structure. The incentive is to reduce installation requirements and costs for subsea installation and tie-ins. The bottom-tow configuration requires the casing be pressurised in order to withstand external hydrostatic collapse, and to allow the use of open-cell polyurethane foam insulation. As design water depth increases, up to several pressurisation stages are required during the tow to site to avoid burst or collapse during tow. Therefore, the maximum bundle length is limited, necessitating mid-line tie-ins of bundle segments. Each such segment must be optionally designed for its appropriate depth range. The leading technical issues for towed bundles in deepwater concern 1) the need for high D/t casings, which lead to low safety factors against burst and collapse, 2) the lack of experience with mid-line tie-ins, 3) the needs for analysis tools and methods to predict bundle thermal performance, and 4) the need to evaluate bundle damage consequences. If a hydrate plug occurs in a singly laid insulated flowline, it may be difficult or impossible to use flowline depressurisation or local chemical treatment to sublimate the plug. Hydrostatic pressure from the fluid column in the deepwater flowline and riser may exceed the minimum pressure required at ambient seawater temperatures. Local chemical treatments may require running coiled tubing to target the chemical at the plug, and the flowline lengths may limit the ability to run coiled tubing in this manner. From an operational standpoint, the bundled flowline configuration provides certain advantages that cannot be realised using individually laid and insulated flowlines. Since all flowlines can be contained within the same insulated space, warm fluids can be circulated through adjacent looped flowlines to sublimate a hydrate plug. Such additional flowlines could be incorporated in the bundle to provide a dedicated circulation loop. Heat-traced flowlines still requires the flowline to be insulated in order to conserve heat, generally using singly insulated pipe or pipe-in-pipe configuration.


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11.6


Pipe-in-pipe system

Rigid, polymeric centralizers placed periodically in a pipe-in-pipe system do not improve the collapse resistance of the outer pipe, unless spaced less than 3 pipe diameters apart. Pipe-in-pipe carrier pipes with higher D/t values exhibited significant increases in collapse resistance and critical curvature when foam insulation completely filled the annulus. Pipe-in pipe flowlines with an evacuated annulus maintained by a platform based pump spread is technologically feasible with available materials, fabrication processes, pumping capacities, and installation methods. However, the operational risks involved with annular flooding will require extensive development of rapid and economic repair technique.

11.7

13% Cr pipe

The application of weldable modified 13%Cr linepipe is considered a cost effective alternative to solid duplex stainless steels and bi-metallics currently used by the Oil & gas industry for subsea Corrosion Resistant Alloy (CRA) pipelines. The use of martensitic 13%Cr stainless steels offer excellent resistance to corrosion in CO 2 containing fluids and consequently have been extensively used as downhole tubular products for the oil and gas industry. More recently, the development of super 13%Cr steels has improved the general corrosion resistance of these materials and offers limited resistance to SSCC in environments containing small amounts of H2S. In the past, 13%Cr stainless steels have been precluded from use as linepipe due to their poor weldability. As these materials are considerably cheaper than duplex stainless steels and offer comparable corrosion resistance in CO2 environments containing small amounts of H2S, there has been considerable interest in recent years for the development of a weldable 13%Cr. On the basis of this, linepipe manufacturers have undertaken extended development programmes to produce a weldable 13%Cr linepipe. This was claimed to be achieved by principally lowering of carbon and nitrogen contents. A testing programme performed by a Group Sponsored project using mechanised PGMAW and manual GTAW with duplex (25%Cr) filler wires has shown good weldability of 13%Cr linepipe similar to duplex stainless steels, and satisfactory welds made in a productive manner with desirable and corrosion properties. 13%Cr steel used for this test has low Carbon and Nitrogen levels to offer good weldability and minimise hardness values in a HAZ. In addition the materials are highly alloyed with Nickel (Ni). All material were supplied in the quench and tempered condition and varied between laboratory and production samples. The addition of Molybdenum (Mo) is claimed to improve SSCC resistance in the HAZ and Ni to obtain a single martensitic phase plus increase toughness. For pipeline welding, a fundamental factor in the selection of the welding process/system is being able to achieve the required weld quality and properties at the desired productivity levels. An additional consideration for CRA’s is the requirement for back purging of the root bead to avoid oxidation. Based on these considerations, the (PGMAW) process using an internal pipeline clamp with copper backing shoes, which supports the solidifying weld pool, was selected. This technique when applied in the form of a mechanised process (welding bug and band system), offers the maximum productivity for a single sided welding technique. One restricting factor with such a technique is the minimum internal pipeline size available with copper backing shoes. This at present is limited to 8’’ diameter pipe size and above. For 6’’ diameter and smaller, this technique has not yet been fully developed for single sided welding without the use of internal clamp with copper backing shoes, therefore, an alternative welding process was selected for these diameters, namely , GTAW.


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11.8 Summary table Pipes C-Mn Steel Pipe

Duplex stainless steel

Clad pipe

Advantages

Disadvantages

-

Low purchase cost

-

Low installation cost

-

Good experience in field welding

-

Good corrosion resistance

-

High purchase cost

-

Good experience in field welding

-

High installation cost

-

Low operating cost

-

Medium purchase cost

-

High installation cost

-


-

Potential problems:

-

Low operating cost

-

Corrosion problem High operating (inhibitor), maintenance and repair cost

1. ‘’Implosion’’ 2. ‘’Interface gap’’ 3. ‘’Residual stress’’ 4. ‘’Weld decay’’

13%Cr

Wet insulated pipe

Flexible

Pipe in pipe

-


-

Field welding to be qualified

-

Medium corrosion resistance

-

Medium installation cost

-

Low operating cost

-


-


-

High U value increasing with time

-

Low compressive strength

-


-

High purchase cost

-

Flexibility on seabed “snagging”

-

Temperature limitation

-

Re-usable

-

Potential problems due to WD:

-


1. ‘’Bird cages’’

-

Low operating cost

2. ‘’Reverse end cap effect’’

-


-

High purchase cost

-

Low U-value

-

Potential problems: 1. ‘’Slippage of internal pipe’’ 2. ‘’Bend radius of reeled pipe’’ 3. “Lost of sealine in case of wet buckle if designed without bulkhead”

Bundle

-


-

-

Onshore fabrication and test

-

-

Low purchase cost

-

Low U-value Integration of subsea equipment and system within bundle

-

Seabed congestion minimised

-

No requirement for burial

Availability of bollard pull tug

Length and weight limitation (e.g. 7 – 20 km) Potential problems: 1. “Line pressurisation’’ 2. ‘’Connection to subsea structures’’ 3. ‘’Controlled depth tow 4. ’’Less flexibility for change in development plan”

Table 10 – Advantages & Disadvantages summary table


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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK RISER SYSTEMS


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TABLE OF CONTENTS 1

2

INTRODUCTION ............................................................................................................ 5 1.1

SCOPE ...................................................................................................................... 5

1.2 1.3

REGULATION, CODES, STANDARDS & SPECIFICATIONS .................................................. 6 DEFINITIONS & ABBREVIATIONS ................................................................................... 6

1.4

REFERENCES ............................................................................................................. 7

1.5

ACKNOWLEDGEMENTS ................................................................................................ 7

PROCESS DESIGN FOR DEEPWATER RISER............................................................ 8 2.1

GENERAL ................................................................................................................... 8

2.2 STEEL RISER SYSTEM ................................................................................................. 8 2.2.1 Design methodology .....................................................................................................8 2.2.2 Selection of the riser section.......................................................................................10 2.2.3 Selection of the basic configuration (static analysis)..................................................10 2.2.4 Dynamic analysis – extreme conditions .....................................................................10 2.2.5 VIV analysis ................................................................................................................11 2.2.6 Fatigue analysis ..........................................................................................................11 2.2.7 Temporary conditions .................................................................................................11 2.3 FLEXIBLE RISER........................................................................................................ 12 2.3.1 Hydrostatic collapse at design water depth (pipe empty condition) ...........................12 2.3.2 Axial compression of the pipe structure due to the reverse end cap load .................12 2.3.3 High tension load in operation of dynamic risers due to pipe weight and dynamic amplification.............................................................................................................................13 2.3.4 Installation loads .........................................................................................................14 2.4 3

DESIGN SOFTWARE FOR RISER SYSTEMS ................................................................... 15

INTERFACE REQUIREMENT...................................................................................... 16 3.1

GENERAL ................................................................................................................. 16

3.2

WITH FLOATING PRODUCTION SYSTEM ...................................................................... 16

3.3 AT SEABED .............................................................................................................. 18 3.3.1 Flexible risers..............................................................................................................18 3.3.2 Top tensioned risers ...................................................................................................20 3.3.3 Hybrid riser tower........................................................................................................21


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RISER SYSTEM REVIEW............................................................................................ 22 4.1

GENERAL ................................................................................................................. 22

4.2 FLEXIBLE RISER SYSTEMS ........................................................................................ 22 4.2.1 Structural description of flexible pipe riser..................................................................22 4.2.2 End fitting ....................................................................................................................24 4.2.3 Bending stiffener .........................................................................................................25 4.2.4 Bending restrictor........................................................................................................26 4.2.5 Riser configurations ....................................................................................................27 4.3 RIGID PIPE RISER SYSTEMS ....................................................................................... 31 4.3.1 General .......................................................................................................................31 4.3.2 Riser configurations ....................................................................................................31 5

6

INSULATION TECHNIQUES ....................................................................................... 45 5.1

GENERAL ................................................................................................................. 45

5.2

SELECTION OF AN INSULATION MATERIAL ................................................................... 45

5.3

INSULATION MATERIAL FOR STEEL RISER AND HYBRID RISER TOWER ............................ 46

5.4

INSULATION MATERIAL FOR FLEXIBLE RISER................................................................ 47

HEATING TECHNIQUES ............................................................................................. 49 6.1 GENERAL ................................................................................................................. 49 6.1.1 Pipeline .......................................................................................................................49 6.1.2 Design criteria .............................................................................................................50 6.2 ELECTRICAL HEATING ............................................................................................... 50 6.2.1 Direct Heating System description .............................................................................50 6.3

7

8

HOT WATER CIRCULATION HEATING ........................................................................... 52

VORTEX INDUCED VIBRATIONS............................................................................... 53 7.1

GENERAL ................................................................................................................. 53

7.2 7.3

VIV PREDICTION....................................................................................................... 53 VORTEX SUPPRESSION DEVICES................................................................................ 55

ARTIFICIAL LIFT REQUIREMENT .............................................................................. 57 8.1

GENERAL ................................................................................................................. 57

8.2 GAS LIFT METHOD.................................................................................................... 58 8.2.1 Internal gas lift using coil tubing .................................................................................59 8.2.2 Internal gas lift lines integrated to production riser.....................................................61 8.2.3 External gas lift line.....................................................................................................62 8.2.4 External common gas lift line......................................................................................64


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INSTALLATION TECHNIQUES ................................................................................... 66 9.1

GENERAL ................................................................................................................. 66

9.2 INSTALLATION OF FLEXIBLE RISERS ............................................................................ 67 9.2.1 Flexible riser in “Free hanging” configuration .............................................................68 9.2.2 Flexible riser in “Lazy S” configuration .......................................................................70 9.2.3 Flexible riser in “Lazy Wave” configuration ................................................................72 9.2.4 Flexible riser in “Steep S” configuration......................................................................74 9.2.5 Flexible riser in “Steep Wave” configuration...............................................................76 9.2.6 Flexible riser in “Pliant Wave” configuration ...............................................................78 9.3 INSTALLATION OF METALLIC RISERS ........................................................................... 80 9.3.1 General .......................................................................................................................80 9.3.2 J lay technique ............................................................................................................80 9.3.3 Tow out method ..........................................................................................................82 9.3.4 Drilling riser running techniques applied to top tensioned risers................................84 10 APPLICATIONS & LIMITATIONS................................................................................ 86 10.1 GENERAL ................................................................................................................. 86 10.2 FLEXIBLE RISERS ...................................................................................................... 86 10.3 STEEL RISERS .......................................................................................................... 87 10.3.1 Top-tensioned riser tower ...........................................................................................87 10.3.2 Steel catenary risers ...................................................................................................88 10.3.3 Offset hybrid riser tower..............................................................................................88 11 ADVANTAGES & DISADVANTAGES ......................................................................... 89


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1

INTRODUCTION

1.1

Scope


A riser is usually a pipe, which connects subsea pipeline (sealine) to the floating platform system. In deepwater field development, the riser can be made out of rigid or flexible pipe in the size range from 2" DIA to 16" DIA depending on requirements. Risers are key components of all offshore production facilities having major economic and safety significance. The riser provides access from the sea bed to the platform facilities for subsea satellite developments (produced oil and gas, test lines, water and gas injection, and control umbilicals), product import and export pipelines and platform utilities (control and power lines). Until now most deepwater projects have extended shallow water technology through the use of new materials (e.g. titanium, composite, etc.) and manufacturing techniques. Although high pipe flexibility is needed to accommodate vessel motions in shallow water, at greater depths stiffer pipe is considered by many to be of worthy consideration because of the beneficial effect of water depth on riser system compliancy. Riser systems are used to transport hydrocarbons from the seabed to the platform facilities, and are dynamic systems which operate at both high pressures and temperatures often with highly corrosive fluids. As a result, they are technically complex and the materials and methods of manufacture and installation make them very costly. These issues are of course compounded as depths increase, due to higher loads and lengths involved making riser system selection and optimisation even more complicated. In recent years new riser arrangements have been conceived to meet the challenge of deep water, offering significant commercial and technical advantages over conventional flexible riser systems. These new riser systems utilise steel pipe which has a relatively low cost compared to flexible pipe. Two of the most promising concepts are the steel catenary riser and the hybrid riser (combination of rigid and flexible pipe). Riser system is a key issue within the offshore oil & gas industries and each riser type (e.g. flexible, steel, composite) and configuration (e.g. Steep, Lazy, Compliant) would be a major engineering topic for further design, analysis, etc… The aim of this document is to review the current state of the art riser technologies, which are well adapted to deepwater field development, and to highlight its key engineering topics, limitations, advantages and disadvantages. This document commences, in chapter 2, with a brief overview of the design process for deepwater riser made out of flexible pipe or steel pipe used in hybrid riser tower, top tensioned riser and free hanging catenary riser. Chapter 3 provides information on top and bottom interfaces requirements for the different riser systems (material and configuration), which are further analysed in chapter 4. Technical solutions such as thermal insulation and heating to mitigate hydrate and/or wax formation later in field life are described in chapters 5 and 6. Chapter 7 discusses deepwater riser vortex induced vibration (VIV) problem affecting riser fatigue life, and provides some options often chosen for VIV suppression. As high well productivity is essential in offshore deep waters, chapter 8 describes one of the most widely used artificial lift method, namely, gas lift. Chapter 9 is dedicated to the installation methods related to the type of riser configurations.


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Applications and limitations on riser material (flexible or steel pipe) are discussed in chapter 10, and chapter 11, Advantages and disadvantages of different riser configurations concludes this document.

1.2

Regulation, codes, standards & specifications • DNV : "Rules for submarine pipeline systems", 1981 – (amended as needed by DNV 1996 Edition) • API RP 2 RD : "API recommended practice for design of risers for floating production systems and tension leg platforms", October 1996 (January 1997) • API RP 14 E : "Offshore production piping systems", October 1996 • API Spec 5L & 5LC– "API Specification for line pipe", May 1984 • API RP 17 B : “Recommended practice for flexible pipe” • API Spec 17 J : “Specification for un-bonded flexible pipe” • ISO 13623 : “Pipelines transportation systems for the Petroleum and Natural Gas Industries • ISO 13628 – Part 2 : “Flexible pipe systems for subsea and marine applications” (in preparation)

1.3

Definitions & abbreviations

Flowline

Sealine

The conduct system e.g. steel pipeline, flexible line, bundle, etc., divided in two parts: static “sealine” section resting on seabed and dynamic “riser” section from seabed to surface “Static” section resting on seabed of a conduct for the flow of liquid or gas

Riser

“Dynamic” part of flowline connecting sealine to the termination point of platform

FPS

Floating production system

FPSO

Floating Production Storage and Offloading

MIT PLEM

Massachusetts Institute of Technology Pipeline End Module or Manifold

PVDF

(Poly-Vinylidene-di-Flouride) innerliner material

RAO

Response Amplitude Operators

ROV SCR

Remotely Operated Vehicle Steel Catenary Riser

S-N

Stress range – Number of cycles to failure

TLP

Tension Leg Platform

TDP VIV

Touch Down Point Vortex Induced Vibration


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1.4


References 1

Offshore technology conference papers from 1969 to 1998

2

In-house technical database

3

In-house experience in rigid and flexible flowline installation

4 5

In-house capabilities of hybrid riser system dynamic analysis Manufacturer and subsea contractor product leaflets

6

Deepwater Field Development – Reference Book – “Tie-in Methods” Document n° TOTAL/Z/EN-004/98 (SEAL Engineering)

7

1.5

Deepwater Field Development – Reference Book – “Sealines” Document n° TOTAL/Z/EN-005/98 (SEAL Engineering)

Acknowledgements



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2

PROCESS DESIGN FOR DEEPWATER RISER

2.1

General

There are mainly two types of riser: (1) flexible riser and (2) steel riser, which are available for the deepwater field development from a floating production system. Each of these technologies have its own design basis as further presented in the following sections.

2.2

Steel riser system

2.2.1

Design methodology

The steel catenary riser design methodology flowchart is presented in the following figure 1.


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Figure 1 – Steel catenary riser design flow chart The design checks related to the different design phases of a steel riser system are described in the following sections.


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2.2.2


Selection of the riser section

A starting point of the design process is the definition of the riser internal diameter as a function of the fluid characteristics and of the required flow rate. The wall thickness is initially defined to guarantee: -

Containment of the maximum internal pressure (bursting)

-

Adequate strength against local buckling due to external hydrostatic overpressure (if any) axial force and bending moments

-

Sufficient strength to resist propagating buckling in absence of buckle arrestors Adequate apparent weight for the on-bottom stability against lateral current loads.

Consideration for corrosion due to internal fluid and to the sea environment shall be performed to identify the actual material characteristics, the required corrosion allowance and the specifications for external coatings (if any) 2.2.3

Selection of the basic configuration (static analysis)

Static analysis is the fundamental step for preliminary definition of the riser configuration. The design water depth, the maximum static offsets and the heave motions imposed by the floater allow the designer to select the most suitable geometry from the possible alternatives. The definition of the riser total length and the amount of buoyancy (if any) are the next step to achieve a well-balanced initial configuration. Such configuration results into a compromise between the top end tension, the peak combined stresses arising in the touch down point (TDP) or in the bent areas (e.g. arch) and the maximum angle variations at the riser terminations. An adequate margin against the expected dynamic amplification must be accounted for starting from this phase, in order to consider realistic data (e.g. dynamic amplification factor, typically within 1.2-1.3 range, is used to determine the dynamic tensions from the static results). 2.2.4

Dynamic analysis – extreme conditions

The mooring system analysis, using numerical or physical models with a statistical representation of the environmental conditions, allows the prediction of the extreme offsets for the floating production system. These values shall be determined for intact or damaged mooring conditions, considering both parallel (current, waves and wind colinear) and transverse weather (current, waves and wind non-colinear) conditions. The transfer functions for the six components of the vessel motion (Response Amplitude Operators or RAOs) in the wave frequency range are usually provided. The top end of the riser is generally subjected to the direct action of waves and current in conjunction with the imposed motion defined by the combination of RAOs with the considered Sea State. The dynamic analysis of the riser is generally based on a time domain approach with non-linear structural and loading models, using both regular and spectral wave conditions. The main parameters subjected to checks are: -

Effective tensions

-

Bending moments and combined stresses along the entire riser length

-

Angular excursions and reactions forces at the top end

-

Transverse riser motions Bending moments and potential compression at the TDP


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Particular attention has to be paid, under severe storm conditions, to avoid excessive axial compression in the lower part of the riser (close to the TDP), which can lead to uncontrolled deflected shape and involve high bending radius and hence buckling of the pipe. 2.2.5

VIV analysis

The need for VIV suppressors should be investigated with respect to VIV effects induced as part of the riser fatigue damage. Should excessive motions be expected, effective suppressors will be selected and applied to the required riser extension. Numerical model of the problem is required in order to evaluate the envisaged solutions. Limited developments have been identified in this particular area and, among these, the widely recognised work of Prof. J.K. Vandiver is a key reference, being also the basis of a specific software (SHEAR7 by MIT) potentially suitable for handling this problem. 2.2.6

Fatigue analysis

The total fatigue damage is assumed being generated by the combined action of the following contributions: -

Mean motions of the vessel caused by the sequence of storms foreseen in the long-term distribution

-

Slow-drift motions of the vessel inside each storm event

-

Wave-frequency motions of the vessel and hydrodynamic loads applied directly to the riser for each of the above events Vortex induced vibrations (VIV) effects in some portions of the riser (e.g. first 100 meters below sea surface level)

-

The admissible fatigue life is assumed to be equal to 10 times the design life for the entire pipe length. Suitable criteria will be defined to couple a particular environmental condition (wave and current) with the corresponding vessel offset. A time-domain approach will be followed to describe the dynamic response of the riser generated by the representative seastates of the long-term distribution. The damage is then evaluated by means of a suitable procedure that shall be aligned with the solution approach, considering a reference S-N (Stress range – Number of cycles to failure) curve like HSE, API X (in RP 2A) and the Palmgren-Miner law for summing the partial contributions. 2.2.7

Temporary conditions

Temporary conditions are generally associated with the life phases of the system before operation. They include: •

Construction: On-shore or off-shore assembly and handling of the riser

•

Transportation: Using surface, immersed or controlled-depth towing methods

•

Installation: Directly operated by the towing vessels or by the laying vessels.

These phases, together with potentially disconnection and retrieval operations, must be considered within the analysis methodology in order that maximum riser responses in transient static and dynamic conditions are captured. The reference meteocean conditions are identified on the basis of the estimated duration of each operation and of the period of the year selected for the activity. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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2.3


Flexible riser

The main design aspects, which need to be addressed in deep water flexible pipe design, are:

2.3.1

Hydrostatic collapse at design water depth (pipe empty condition)

In conventional flexible pipe, the internal carcass has been designed to provide all of the collapse resistance to the flexible structure. The pipe must be designed to have sufficient collapse resistance with the outer sheath damaged. In this case, the external hydrostatic pressure penetrates the structural layers (pressure and tensile armours) and bears against the fluid barrier. For deepwater application, a solution to provide additional collapse resistance without adding substantial weight will consist in modifying the pipe structure such that the external hydrostatic will bear outside the pressure armour. Thus both the pressure armour and the carcass will provide internal ring stiffness increasing the collapse resistance. Further improvements in the collapse resistance for larger diameter and deeper water requires increased ring stiffness of the internal carcass and/or pressure armour.

2.3.2

Axial compression of the pipe structure due to the reverse end cap load

The axial compressive stiffness of conventional flexible pipe is an order of magnitude lower than the tensile stiffness. When a flexible pipe is subject to axial compression, the tensile armour layers expand radially (i.e. increase of the diameter under compression known as Poisson's effect), with resistance to expansion provided by the helical wrapped tape over the tensile armour and the external sheath itself. The reverse end cap load in deep water is substantial. For example, a 6" ID empty pipe at a water depth of 2000 meters is subject to more than 80 tonnes reversed end cap load There are three potential modes of failure of the flexible pipe resulting from the reverse end cap load: -

Buckling of the tensile armour wires themselves Rearrangement of the tensile armour layers resulting from the radial expansion

-

Failure of the outer sheath

If the flexible pipe is not torsionally balanced under axial compression, or has residual torque due to the manufacturing, reeling or installation processes, then the resulting twist can increase the radial expansion of either the outer or the inner tensile armour layer. This would increase the potential for these failure modes to occur. Thus torsion loading must also be considered in evaluating the resistance of a flexible pipe structure to reverse end cap loads.


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2.3.3


High tension load in operation of dynamic risers due to pipe weight and dynamic amplification

In order to reduce the tension loads on flexible pipe for deep-water applications, a system approach can be applied. Multiple flexible pipe structures are used with a mid-line connection between the pipes. The top section is designed for higher tensile capacity and the lower section is designed for high collapse resistance. This approach saves substantial weight over making the entire pipe designed for both the required collapse resistance and top tension capacity. The high tension capacity pipe can be made with composite tensile armour to result in further weight reduction. The estimated weight saving versus steel armoured pipe by using a combination of steel structures composed of high tensile capacity top section and high collapse resistance bottom section is 25%, and 50% for high tensile capacity top section with composite armour and high collapse resistance bottom section with steel armour Figures 2 and 3 present the pipe design and capabilities of the composite armour relative to the steel material currently being used. In addition to weight reduction, the composite armour offers the advantage of being essentially inert to corrosion, hydrogen induced cracking and sulphide stress cracking, all potential mechanisms for reducing the service life of a flexible pipe. LAYER

MATERIAL NYLON 11

FLEXSHIELD FLEXTENSIBLE FLEXWEAR

NYLON 11

FLEXTENSIBLE FLEXWEAR

CARBON STEEL NYLON 11 CARBON STEEL

FLEXLOK FLEXBARRIER FLEXBODY

CARBON STEEL

FUNCTION EXTERNAL FLUID BARRIER TENSIBLE STRENGTH LAYER ANTI-WEAR LAYER TENSIBLE STRENGTH LAYER ANTI-WEAR LAYER HOOP STRENGTH LAYER FLUID BARRIER

NYLON 11 or PVDF STAINLESS 316L

COLLAPSE RESISTANT LAYER

Figure 2 – Non-bonded flexible pipe structure

LAYER FLEXSHIELD FLEXTENSIBLE

MATERIAL NYLON 11 COMPOSITE

FLEXWEAR

NYLON 11

FLEXTENSIBLE

COMPOSITE

FLEXWEAR FLEXLOK FLEXBARRIER FLEXBODY

NYLON 11 CARBON STEEL PVDF DUPLEX 220S STAINLESS

FUNCTION EXTERNAL FLUID BARRIER TENSIBLE STRENGTH LAYER ANTI-WEAR LAYER TENSIBLE STRENGTH LAYER ANTI-WEAR LAYER HOOP STRENGTH LAYER FLUID BARRIER COLLAPSE RESISTANT LAYER

Figure 3 – Non bonded flexible pipe structure using composite armour material


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The following table provides mechanical properties comparison between steel and composite materials: Steel

Configuration

Carbon Fiber Composite

Cold rolled/Heat treated

Thermoplastic/Carbon fiber matrix

Rectangular cross section

Rectangular cross section

3 – 6 mm thick

1 – 2 mm thick

Mechanically performed to helical 2 – 4 layers structure Helically wrapped Strength

759 Mpa

1,255 Mpa

Modulus

207 Gpa

80.7 Gpa

Elongation

11% or higher

1.4 %

Density

7.85g/cc

1.48g/cc

Table 1 – Mechanical properties comparison

2.3.4

Installation loads

The flexible pipe structure must be designed to withstand the following installation loading conditions: -

Radial compression with tension to simulate loading condition at tensioner External hydrostatic pressure, zero internal pressure with and without bending and torsion Tension and radial compression loads on external sheath

The pipe structure is checked by stress analysis to verify that it can withstand these combined loading conditions. Where necessary, the pipe layer dimensions or materials are modified to assure that the loading is within the allowable utilisation factors prescribed in API specification 17J.


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2.4


Design software for riser systems

Time domain non-linear dynamic analysis: •

Flexcom 3D (developed by MCS International)

•

Visual Orcaflex (developed by Orcina)

•

Deepline (developed by IFP)

•

TIARA (Total Integrated approach to Riser analysis with VIV analysis, developed by Shell)

•

RICOL (developed by Marintek)

Finite Element, Frequency domain, Time domain non-linear analysis: •

ABAQUS (developed by ?)

•

COSMOS (developed by Structural Research & Analysis Corp)

Vortex Induced Vibration analysis: •

Shear 7 (developed by MIT)

•

VIVA (developed by DTCL ltd)


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3


3.1

General

The main interface requirements in the riser design are related to: -


-


-

Subsea connection and tie-in methods

-

Lay vessels and methods (e.g. J-lay, Reel lay and Towing)

-

Attachment point on the floating production system

-

Anchoring point at the seabed

This study will address only the two last topics as the other subjects have already been covered in the documents "Tie-in Methods" (Reference 6) and "Sealines" (Reference 7) of Deepwater Field Development - Reference Book.

3.2

With Floating Production System

Considering FPS such as semi-submersible, SPAR or TLP, the hang-off point can be either at the pontoon level or at the deck level with the following advantages and drawbacks: -

-

Interface at pontoon level allows the riser to avoid the dynamic wave splash zone, hence avoiding high environmental loads and eliminating the risk from accidental vessel impact. This solution has the disadvantage of involving subsea connection, which complicates the connection installation, inspection and maintenance. A deck level hang-off point has the advantage of being an above water connection. However it require the riser to pass through the splash zone and increases the reversal efforts applied on the floating production system (as riser tension is applied above the centre of buoyancy) with a consequent impact on stability and payload.

For flexible riser, a hanging device is used to maintain the top of a riser on a support fixed to the floater, for example at the top of a I or J tube. The I or J tubes are designed to protect the riser against environmental loads (wave and current) and accidental collisions with vessel (see figure 4). They are often equipped with a bell mouth system using mechanical dogs to hold the riser bending stiffener with a conical structure facilitating the riser entry and allowing angle deflection.


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Riser Pulling Head Hang-Off System

I Tube

Flange

Unlock Ring

Polymeric Spring Dogs Device

Figure 4 – Top attachment arrangement of flexible riser In the case of rigid riser hung in a free catenary, a flexjoint receptacle fixed to the pontoon or deck level acts as a hanging point (see figure 5). Pre-Installed Hull Piping

Spool Piece Support Clamp Field-Installed Spool Piece

End Connection

Flexjoint

Guide Ring / Wear Bushing Main Housing

FPS Elastomer Element

Installation Bumper

Flexjoint receptacle

Catenary Riser

Figure 5 – Top attachment arrangement of steel catenary riser For the top-tensioned risers, a tensioning system is required to support the riser, maintain required tension and compensate for the relative motions of risers and platform. From a semi-submersible platform, riser is typically supported by hydro-pneumatic cylinders and lines rigged through sheave blocks to magnify the movement of the cylinders and so allow large relative motions between the platform and the riser. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The amount of relative motion between the TLP and the riser is small and simple hydraulic/pneumatic cylinders may be connected directly to the riser at the special "riser tensioner joint". In a Spar platform, the risers will only require a simple static tensioning system to be used mainly during the riser installation. Once the desired mean tension is achieved the risers may be locked off with the buoyancy cans attached to the riser and compensating for the platform movements (see section 4.3.2 II.).

3.3

At seabed

The free hanging (rigid or flexible) catenary riser system is characterised by the absence of additional hardware components except at the seabed connection to a steel sealine. This sealine can be terminated by either a mechanical flange or a pipeline end module requiring a mechanical connection and a jumper installation respectively. In the other configurations and depending on the type of risers, the following subsea interfaces are required:

3.3.1

Flexible risers

In order to increase the riser system compliance (particularly in relative shallow waters), the Lazy "S" or Steep "S" configurations can be adopted (see section 4.2.5). Mid-water arches are used to support the risers in these configurations (see figure 6). The mid-water arch and associated subsurface buoy is tensioned by means of a sling and a dead weight in the case of a lazy "S" configuration, and by means of the flexible pipe itself in the case of a Steep "S" configuration (see figures 16 and 18). The mid-water arch keeps the flexible riser at an acceptable curvature. Buyancy modules

Mid-water arch

Flexible risers

Figure 6 – Mid-water arch supporting flexible risers


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In the wave configurations, the mid-water arch is replaced by buoyancy modules consisting of two parts (see figure 7): -

A steel clamping system which ensures the attachment of the buoyancy module to the flexible.

-

A buoy with a torus shape. The material used for this buoy (usually a syntactic foam) is designed according to the water depth.

Buoyancy module

Figure 7 – Distributed buoyancy modules being installed on flexible riser The anchoring base of a riser in Steep "S" or Steep "Wave" configuration consists of a steel and/or concrete structure. It may include piping, valves and elbows (see figure 8). RISERS

CONCRETE SLAB

SPOOL PIECE TO TEMPLATE

Figure 8 – Typical riser base for Steep system The soil conditions are an important parameter. In fact, the angle of the subsea end fitting of a riser in a Steep "S" or Steep "Wave" configuration has to be carefully controlled and depends on the riser base being horizontal (+/- 2°). The riser base is generally stabilised by its own weight, but can be piled if soil conditions so require. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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3.3.2


Top tensioned risers

For the top tensioned risers, the riser base is a steel structure mounted on a well template or a subsea manifolding template and equipped with a male hub facing upwards for connection to the riser by means of tie-back connector (see figure 9).

Figure 9 – Riser base mounted on subsea template


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3.3.3


Hybrid riser tower

In the hybrid riser tower, a riser base is placed on the seabed to provide an anchoring system to resist tension loads. In addition the riser base acts as a connection point between the sealine coming from the wells or manifolds to the vertical riser. The riser base consists of a central core structure housing the foundation receptacle, which is attached to a template structure. The riser base-foundation may be piles (steel), gravity (concrete) structures, suction caisson or a combination thereof. Typical installation inclination relative to vertical is +/- 2°.

Gas Injection Valves With Protective Cage

Riser Riser

Plate Girders Riser Funnel

Pinned Stress Joint Riser Bottom Connector

Concrete Ballast

Seabed Concrete Infill Foundation Receptacle

Suction Pile

Foundation Receptacle

Typical Riser Arrangement Suction Pile

A/ SIDE VIEW

B/ TOP VIEW

Figure 10 – Subsea foundation for hybrid riser tower


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4

RISER SYSTEM REVIEW

4.1

General

A riser system must be designed/selected to adapt the following requirements: •

Provide enough flexibility to allow for FPS motions: -

First order wave motions.

-

Second order wave motions (slow drift).

-

Static offset due to environmental loads.

-

Static offset after mooring line failure.

•

Acceptable behaviour under environmental conditions encountered (i.e. resists to the environmental loads and especially current loads, avoids riser clashing, and overreaching of the maximum loads which can be withstood by the floater or the riser base).

•

Satisfy the flow assurance requirements:

•

-

Sufficient insulation or heat supply.

-

Resistant to the fluid aggressions (i.e. internal pressure, corrosion, erosion).

-

Artificial lift means if required (e. g. gas-lift, multi-phase pump)

Resist to transportation/laying loads (i.e. external overpressure, eventually clamping pressure onboard the laying vessel, etc.).

A wide range of riser configuration concepts have been designed and sometimes applied. Variations occur due to the specific requirements of each application. These configurations can be distinguished on the basis of: •

The structural properties of the riser section (i.e. rigid or flexible) and the materials

•

The cross-section complexity (i.e. mono-bore or multi-bore)

•

The general arrangement/configuration.

4.2

Flexible Riser Systems

4.2.1

Structural description of flexible pipe riser

Non-bonded flexible pipe has been applied in the offshore oil and gas industry for about 20 years. It is used for dynamic risers connecting seabed flowlines to floating production systems, and for static seabed flowlines. In some cases flexible pipe has proved to be more economic than rigid pipe: in harsh environments or when it is desired to recover the flowline for reuse after a short field life. The basic flexible pipe design (see figure 11) consists of a stainless steel internal carcass for collapse resistance, an extruded polymer fluid barrier, a carbon steel interlocked hoop strength layer, helically wound carbon steel tensile armor for axial strength, and an extruded watertight external sheath. For dynamic applications extruded polymer or tape polymer antiwear layers are applied between adjacent steel armor layers. For extremely high pressure applications, an additional layer of rectangular shaped helical reinforcement over the interlocked hoop strength layer, or a second set of tensile armor layers, may be applied. The Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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flexible pipe structure is inherently thermal resistant and corrosion resistant. Thermal insulation layer(s) can be added under the external sheath to provide additional thermal resistance. Internal carcass

Fluid barrier Hoop strength layer

Anti-wear layers

Tensile Armors

External sheath

Figure 11 – Non-bonded flexible riser construction This pipe structure design has been employed successfully in water depths up to 1710 meters on Marlim Sul 3 in Brazil 1997. Recent plans to produce oil and gas from subsea wells in 1000 – 2000m water depths pose new challenges for flexible pipe and other offshore technologies. The material of main layers used in flexible pipes are outlined in the following table 2: Designation of layer

Material used

Thermoplastic tube


Interlocked steel carcass

Galvanized steel, AISI 3O4, AISI 304L, AISI 316, AISI 316L, Duplex, etc.

Thermoplastic sheath


Teta spiral or hoop strength layer

Low or medium carbon steel

Reinforcing layer


Thermoplastic friction sheath

Polyamide 11, High Density Polyethylene

Double crosswound armors


Insulation foam

Cofoam, Carazide, hollow macrospheres + resin binder

glass

micospheres

–

Table 2 – Materials used in the flexible structure

The current flexible technology is restricted in terms of design pressure, water depth and design temperature. These parameters are interdependent and also vary with the line diameter. Typical values are 8000psi as a maximum design pressure, about 1500m maximum water depth and a maximum design temperature of 130°C. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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For example, 9" production flexible risers (5700psi and 130°C) and 9" gas injection risers (7200psi and 90°C) were installed as part of the Asgard project (300-320m water depth), which represented a technical challenge in the use of the flexible technology. It is generally agreed that the “Flexible” technology has reached its maturity and the current development would extend its application within the next 2-3 years, as follows: Maximum size

8” ID

12” ID

16” ID

Deepwater application

1400m

1400m

1000m

Ultra deepwater (under development)

3000 m

2500m

1500m

Design pressure

7000 psi

3000psi

4.2.2

End fitting

Flexible riser is terminated with two end-fittings composed of (see figure 12): -

The termination which ensures the seal and the mechanical attachment of the endfitting to the flexible pipe

-

The connector to allow the connection of the end-fitting to any other compatible connector. All types of connectors can be supplied with any end-fittings, the most common being API hubs (formerly "CIW hubs"), hammer unions and flanges.

Flexible

Bend Stiffener

Termination

Connector

Figure 12 – Flexible pipe end fitting


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4.2.3


Bending stiffener

In dynamic risers, the smallest bending radii (i.e. higher bending moment) are generally found near the end fittings at the connection with the floating production system. In order to avoid any over-stressing of the flexible pipe at this location, a moulded plastic bending stiffeners are placed around the riser (see figure 123). Their conical shape ensures a smooth transition between the end fitting and the riser.

Bending Stiffener

Figure 13 – Bending stiffener mounted on riser


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4.2.4


Bending restrictor

A bending restrictor is made of several vertebrae which physically limit the curvature of the flexible pipe to an admissible radius (see figure 14). The bending restrictor is used mainly: -

At the bellmouth of a J tube (e.g. to control the bending load and the minimum bending radius).

-

At the horizontal connection of a wellhead or a template, when the distance between the connection and the sea-bed is important (i.e. to control the bending radius)

-

As external protection for the flexible pipe (e.g. when crossing a large diameter rigid pipe).

-

In order to avoid any over-bending during installation, generally when the flexible is connected to a structure (plem, automatic connector, skid, etc.) before installation.

Bending restrictor

Figure 14 – Bottom end riser termination equipped with a bending restrictor


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4.2.5


Riser configurations

Flexible risers have been used extensively in recent years for floating and early production systems. Such risers offer the advantage of having inherent heave compliance in their catenary thereby greatly reducing the complexity of the riser-to-rig and riser-to-subsea interfaces. In shallow waters and mild environments the risers have been used in a simple catenary. With increasing water depths coupled with severe environments several alternate configurations have been used and proposed, namely, the Lazy S, Steep S, Lazy wave, Steep wave and Compliant wave. These different configurations are available on a custom design basis. The choice of the adequate configuration is made according to different parameters such as: -

Weather conditions Water depth

-

Number of lines

-

Crowding of seabed

-

Surface floater motions Maximum platform admissible loads

-

Current profile

-

Ease of installation

-

Etc…

The different flexible riser configurations are described below: I.

"Free Hanging" configuration (see figure 15)

This is the configuration of a flexible riser which runs in a catenary shape from the upper connection point on the floater straight down to the seabed where it can be connected to any of subsea equipment (flexible sealine, plem, satellite tree, subsea manifold, etc.).

Flexible riser

Sagbend

Figure 15 – Flexible riser in "Free Hanging" configuration


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The flowline system can be either all flexible pipe, or a combination of rigid sealine and flexible riser. The installation of a flexible riser / rigid pipe consists in basically, after a steel pipe has been installed and abandoned on seabed, retrieving the rigid line by the flexible pipe lay vessel and connecting above surface a flexible flowline end segment. The entire assembly is then lowered to the seabed and the continuation of flexible flowline installation continues till the transfer of riser flowline to the floating production system. At seabed sagbend location, the FPS first and second order motions can induce compression buckling in the flexible, or problem of pipe embedment in soft soil, especially in the case of an FPSO. If this appears to be critical, the solution may be to adopt another riser configuration such as "Wave" or "S".

II.

"Lazy S" configuration (see figure 16)

This is a configuration where a dynamic flexible riser runs down to the sea bed in a double catenary shape from the upper connection on the floater via a subsurface buoy, and a mid-water arch. The lower part of the flexible riser lies on the sea bed. The midwater arch and buoy are tensioned by means of a sling and dead weight. The mid-water arch keeps the flexible riser at an acceptable curvature.

Flexible riser

Dead Weight Mid-water arch (with sub-surface buoys)

Figure 16 – Flexible riser in "Lazy S" configuration


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III.


"Lazy Wave" configuration (see figure 17)

This is a configuration where a loop is formed between the upper connection and the seabed by clamping buoyancy modules along a given section of the dynamic flexible riser. The lower part of the riser lies horizontally on the seabed. The Lazy Wave configuration is a straight forward extension of the classic Lazy S configuration where the mid-water arch, and associated subsurface buoy, sling and dead weight are replaced by a number of buoyancy modules.

Flexible riser

Buoyancy modules

Figure 17 – Flexible riser in "Lazy Wave" configuration IV.

"Steep S" configuration (see figure 18)

This is a configuration where a flexible riser runs down to the sea bed in a catenary from the upper connection on the floater, via a subsurface buoy and mid-water arch. The flexible riser itself is tensioned by the subsurface buoy and the mid-water arch, and is connected to a riser base at the subsea connection point.

Flexible riser Mid-water arch

Riser base

Figure 18 – Flexible riser in "Steep S" configuration Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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V.


"Steep Wave" configuration (see figure 19)

This is a configuration where a loop is formed between the upper connection and the seabed by clamping buoyancy modules along a given section of the dynamic riser base. The lower part of the riser is connected to a riser base. The Steep Wave configuration is a straight forward extension of the classic Steep S configuration where the mid-water arch and associated subsurface buoy are replaced by a number of buoyancy modules. The Steep wave configuration is perfectly adapted to the Early Production and Testing vessel concept. The basic idea behind this concept is to simultaneously generate reservoir data through extended well testing and provide early cash flow by export of the produced crude/gas. Such a vessel is typically used for a few months on a field where reserves are not yet known with the accuracy required for the definition of a comprehensive development scheme.

Flexible riser Buoyancy modules

Riser base

Figure 19 – Flexible riser in Steep Wave configuration


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VI.


"Pliant Wave" configuration (see figure 20)

This is a configuration where a loop is formed between the upper connection and the seabed by clamping buoyancy modules along a given section of the dynamic flexible riser. The lower part of the riser lies horizontally on the seabed. One end of the lower part is connected to the subsea production system and the other end is attached to a dead weight to withstand the uplift generated by the buoyancy modules.

This configuration is well adapted to a field development using a floating production platform located directly above the subsea production system and flexible lines to connect the subsea wells to the floater.

Flexible riser

Buoyancy modules

Dead Weight

Figure 20 – Flexible riser in Pliant Wave configuration

4.3

Rigid pipe riser systems

4.3.1

General

Flexible risers have been extensively used for the field development based on the main floating production systems (i.e. semi-submersibles, FPSO’ s). With the increase of water depth, there are technical and economic limitations in the manufacturing of large diameter flexible risers: collapse due to high hydrostatic pressure, reverse end cap effects, etc. A rigid steel riser system can provide a technical and cost effective alternative to the high procurement cost for flexible lines, which cannot always compensate for their lower installation costs.

4.3.2

Riser configurations

The main rigid pipe riser system configurations are: −

Top tensioned riser tower (semi-submersible application)

−

TLP or Spar top tensioned riser

−

Steel catenary riser

−

Hybrid riser tower


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I.


Top Tensioned Riser Tower applied to Semi-Submersible (see figure 21)

This riser configuration has been implemented by Enserch Exploration Inc on Green Canyon block 29 (466m WD) in 1988, recovered for refurbishment in 1990 due to reservoir declared non-commercial, and reinstalled on Copper Garden Banks 388 (638m WD) in 1995 in the Gulf of Mexico. The Top Tensioned Riser utilises a rigid, buoyant production riser with a titanium stress joint at the base. Titanium was selected for the stress joint material due to its reduced modulus of elasticity (about half of the steel Young's modulus, which is equal to 207,000Mpa) and its resistance to the fatigue and the effects of corrosion in sea water. The riser, connected at its base to a multi-slot template, provides individual access and surface control to each well and can remain connected throughout the life of the field including 100-year storm conditions. The top of the riser is located 55m below sea level and is connected to the floating production system by tensioning tethers. The depth of the riser top is selected to minimise the action of the waves and still allow air divers to work at that level. Flexible flowlines and umbilical make the connection between porches mounted on the rig pontoons and the upper riser connector package on top of the riser. The rigid riser is installed in a manner similar to conventional drilling riser running techniques. The production, annulus, oil and gas export lines use standard tubing and line pipe and all are installed into the riser through the rotary table using conventional methods. Water Line

Pontoon Tensioner centralizer Package

50 m

Riser connector

Riser umbilical

Flexible Pipe Tensioner cables Upper Riser Connector

Tensioner Sheave Package Flexible pipe

30 m

Upper Riser Buoyancy Air Tanks

Top of Riser Tower

365 m

Buoyant Guide & Support Column Tapered stress joint

15 m

Lower Connector Riser Base

Template Seabed

Figure 21 – Top tensioned riser applied to semi-submersible (Enserch Green Canyon) Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The Top Tensioned Riser consists of the following main components from the bottom to the top: -

Riser base (positioned permanently on the pile anchored template)

-

Lower riser connector

-

Stress joint (e.g. in titanium alloy)

-

Riser joints

-

Upper riser connector package

-

Riser tether system

The Enserch Green Canyon riser tower components are described below: Riser base The riser base consists of a hub profile centered between four radially located posts and four pile sleeves. Vertical female receptacles surround the hub to provide production/annulus/oil export line connections to the riser. Within the central hub connection, at a slightly lower elevation than the others, is a vertical receptacle for the gas export line. Lower riser connector The lower riser connector provides the structural link between the riser stress joint and the riser base at the template. The connector will transmit the tensile and bending loads from the riser to the riser base. The lower riser connector guides the riser onto the riser base and orients the riser for subsequent installation of the production annulus and export tubing. The connector allows the riser to be hydraulically locked to the riser base during installation and released for retrieval. The connector is a field proven collet type connector which is modified to increase its bending capacity. The centre section of the connector has a stinger which extends into the mating hub to provide a moment carrying interface. This allows the collet segments to carry all tensile loads and only a portion of the bending moment. Titanium Stress joint The stress joint provides required flexibility and stress reduction between the riser connector and lowermost riser joint. Steel transition spools at each end have flange - hub connections. The lower flange connects to the lower riser connector, while the hub clamps to the stress joint. The upper spool hub clamps to the tapered end of the stress joint, while a bolt flange connects to the lowermost riser joint.


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Riser joints The rigid riser is constructed of long bolt flange to flange steel joints. When fully assembled the riser has sufficient buoyancy to make it free standing so as to reduce the deck loads on the vessel. This buoyancy is provided by three separate methods. Each individual joint has passive syntactic foam, which offsets the weight of each riser joint. The syntactic foam made the joints lightly negatively buoyant in seawater. In addition to the syntactic foam modules, each joint has an independent internal air can which provides air buoyancy to offset the weight of the production and annulus tubing. The air cans can be filled through an umbilical or independently filled or vented by an ROV. Five large air tanks are installed near the top of the riser. These tanks provide the buoyancy needed during the installation phase, and also allows the riser to withstand 100year storms and loop currents, even when it is disconnected from the rig. Fiberglass guide tubes (to guide the production lines) are moulded in the syntactic foam modules mounted around the structural member. Each joint has twelve quarter sections of foam. On the outside of each foam module are attachment points for vortex strakes and umbilical guides that are bolted and banded in place as joints are run through the moonpool. Bolted to the uppermost riser joint with a flanged connection is the upper riser mandrel, which acts as the structural connection between riser and the upper riser connector package. The assembly includes a hub profile at its upper end surrounded by a guide plate to locate riser guide tubes for flowlines and four guided posts to align the upper riser connector package. Upper riser connector package The upper riser connector package acts as the interface point between the rigid riser and flexible flowline jumpers to the rig pontoon. It is locked in place by a collet connector at its lower end. Around the main collet connector are "mini" collet connectors that lock to the annulus and production lines when the upper riser connector package is landed on the riser. Goosenecks attached to the mini-connectors make an 180-degree bend and terminate in a clamp hub facing down. Flexible lines are attached to these hubs and hang in a catenary shape to pontoon connection points on the floater. The export line is also located radially from the central collet connector with a similar connector. In normal operating conditions, the mini-connector/gooseneck assemblies are each free to move independently in the vertical direction. This movement is necessary to compensate for vertical tubing deflections due to riser deflection, temperature effects, and pressure effects. Riser tether system Although the production riser tether system utilises drilling tensioned components, it is more accurately described as a riser centraliser than as a riser tensioner. The riser is free standing and does not depend on the tensioner for structural support. If the floater moves away from the top of the rigid riser by the environmental forces, the flexible flowlines take a shallower catenary curve. Without the restraint of the tensioner system, the flexible flowlines would have to be significantly longer to prevent damage to their terminations and would consequently cause greater stresses in the riser due to increased weight and drag. Applying a restraining force to the top of the rigid production riser and limiting its motion relative to vessel keeps the flexible flowlines to an optimum length and allows them to remain connected during the most severe environmental conditions. The tether system has line travel capability that is adequate to keep the riser top in an appropriate position below the vessel. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The production riser tether system consists of the following: -

Riser interface sheave package

-

Riser tether centraliser structure (fairleaders and turndown sheaves)

-

Wire rope tensioners

-

Tether control system

-

Production riser tensioner slipping winches

The tensioner lines exit the fairleader on the floating production system and travels through the water to the riser interface sheave package, which is attached to the gas export line hub on the upper riser connector package by a manual diver assisted connector below the ocean surface. The tensioner cables are centralised by means of a riser tether centraliser structure. This structure consists of fairleaders mounted to the rig structure below the water line. Six wire rope tensioners are mounted on the deck of the floater. All six tensioners operate together to produce the required riser tension thereby controlling the riser excursion within the necessary radius. The wire rope tension is controlled from the tether control system, which regulates the flow of air high pressure supplied to pneumatic tensioners.

II.

Top Tensioned Riser applied to TLP and Spar (see figures 22 and 23)

The Neptune Field development is the first Spar-based floating production system using multiple top tensioned production risers from seafloor wellheads back to the surface trees in the Gulf of Mexico at a water depth of 580m. Rigid risers act as tensioned beams. To avoid buckling under its own weight, and excessive bending stresses under lateral wave, current and vortex shedding loads, the riser is tensioned. In a TLP, there is still a small amount of movement of the risers and platform. Its riser system uses simple tensioning system composed of hydraulic cylinders. In the case of the SPAR buoy, there are still considerable vertical movements and buoyancy cans are used instead of the cylinders, taking advantage of the deep draft of the SPAR hull, which protects the buoyancy cans against the waves/current action. In both cases, flexible jumper pipes are used to link the trees to the fixed piping of the platform. The following section will consider this more complex top tensioned riser applied to SPAR.


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Surface Tree Sea Level

Buoyancy Modules

Bottom of Spar Hull Keel Joint

9 - 5/8 Riser

Figure 23 – Top tensioned riser applied to TLP

Surface Tree & Wellhead

Tapered Stess Joint Tieback Connector Subsea Wellhead Seabed

Hydraulic-Pneumatic Tensioners Tensioner Joint

Figure 22 – Top tensioned riser applied to Spar

Splashzone Joints Sea Level Riser Coupling

Riser Joints

Stress Joint

Tieback Connector Seabed

In this configuration, the riser system provides a pressure-contained link between surface tree and seafloor wellhead system. Each riser system acts as an extension of the well's production casing string providing primary pressure containment during well maintenance and work-over operations and secondary pressure containment during routine production. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The production riser system provides guidance for downhole equipment and various maintenance and stimulation activities associated equipment. Each riser has an internal diameter compatible with the well's production casing. Well production, gas lift/annulus access and downhole control are through dual tubing strings and umbilical lines within the riser. Riser installation uses casing installation equipment and techniques. Component assembly during installation is limited to make up of threaded-and-coupled connections. The few flanged connections within the string are pre-assembled and tested on shore. The SPAR production riser system consists of the following main components (see figure 24): -Buoyancy cans -Adjustable riser support structure -Keel joint -Riser joints -Tapered stress joint -Tieback connector -Centralising riser joints -Waveform joint -Tubing spool

Wellhead

Riser Centraliser

Upper Riser Transition joint Riser Joint Foam Buoyancy

Lower Riser Transition Joint

Production Deck Level Mean Water Level

Keel Joint

Keel Joint Wear sleeve

Upper Riser Transition Joint

Bouyancy Can

Riser Within Spar

Riser Centraliser

Stress Joint Standard Riser Joint Tie Back Connector

Figure 24 – Detailed description of Neptune SPAR production riser


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Functionality of these components are described below: Buoyancy cans Each riser is independently tensioned by long buoyancy cans (which volume depends on the riser submerge weight). Stem from the upper can extends upward to the underside of the surface wellhead providing riser support. The lower two cans can be either flooded with water or displaced with air through two service lines running back to the production deck. The cans are fabricated in steel structures and lowered into the SPAR well slot as a single assembly using a crane barge. The buoyancy cans are sized to support the riser, surface wellhead, tubing strings, and tree. Adjustable riser support structure The adjustable riser support structure is a tool temporarily used to support a riser when weight increases are anticipated and at the same time allowing vertical adjustment to prevent riser over tensioning. If environmental conditions worsen to the point where allowable motions may be exceeded, the riser is lowered into a controlled buckled configuration and supported by the adjustable riser support structure. This prevents riser over-tensioning that might result from increased displacements of the Spar. Tieback connector The tieback connector is the lowermost component in the production riser string and is part of a riser subassembly that includes a Titanium stress joint and lower riser transition joint. By making theses items a subassembly, critical flanged connections are made up and fully pressure tested before they are shipped offshore. The tieback connector is remotely locked through an ROV hot stab to the wellhead housing, forming a pre-load structural connection and pressure containing interface with a through bore. At the upper end of the tieback connector, a compact flange with beryllium-copper radial interference seal forms the load and pressure containing attachment to the stress joint. Titanium stress joint The use of Titanium stress joint reduces stresses in the riser and bending moments applied to the tieback connector due to its flexibility. This is especially critical during lateral offsets for the drilling operations. The stress joint is made from a high strength alloy, Ti-6A1-4V ELI. The Titanium stress joint consists of cylindrical tubes. The two tubes with different OD are welded together and compact Ti flanges are welded to each end for connection to the steel flanges of interfacing components. The flanges incorporate radially energised metal-to-metal beryllium-copper seals. To prevent deleterious galvanic corrosion between the Titanium and steel, each steel flange is Inconel 625 overlaid. All the outer surfaces of the stress joint, plus the two flange connections are encapsulated in an elastomeric coating to prevent hydrogen absorption by the Ti and mitigate galvanic interaction between Ti and steel.


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The lower riser transition joint is the uppermost part of the bottom subassembly and forms the pressure containing and structural crossover between the Titanium stress joint and production riser string. The upper connection to the riser string is a threadedand coupled TCII. For corrosion protection, the outer surfaces are coated with thermal sprayed aluminium. Riser joints The bottom 3 riser joints have syntactic foam buoyancy modules. If a riser undergoing work-over operations is lowered on the adjustable riser support structure and supported by the Spar, its lower end goes into a controlled buckled configuration. The buoyancy modules provide additional lift reducing the curvature in this area of the riser. The syntactic foam, sized so it easily passes the buoyancy cans, is attached around standard riser joints and vertically restrained by thrust collars. The riser strings use TCII threaded-and-coupled connections. This connection creates a joint efficiency approaching that of L80 pipe in tension and compression with radially energized metal-to-metal seal. The use of threaded-and-coupled connection allows the use of conventional casing string installation techniques and equipment. For corrosion protection, the riser's outer surface is coated with thermal-sprayed aluminium. The coating acts as a combination barrier coating and cathodic protection system. Keel joint The keel joint provides a pressure containing conduit, hull to riser wear surface, and a reaction point for load transfer between the riser and Spar. The keel joint prevents detrimental wear using a wear sleeve that rides within a bushing at the keel of the Spar. The wear sleeve is attached to and supported by the inner pipe with a elastomeric bearing at each end. Lateral loads between the Spar and riser cause localized bending and the much-stiffer wear sleeve limits the inner pipe deflection by distributing the load through the elastomeric bearings and allowing the inner pipe to deflect into a curved configuration. The keel joint is also a threaded end coupled joint. Because of the pipe size differences, transition joints are used above and below the keel joint to crossover to the riser string. Centralising riser joints Above the keel joint and inside the hull the riser is made of standard casing. As the riser comes up through the hull, it enters the buoyancy cans where it is laterally supported by centralising riser joints. The centralisers are standard riser joints with neutrally buoyant 3m long syntactic foam modules. Like the buoyant riser joints, these foam modules are pre-installed on a standard riser joint and vertically restrained by thrust collar assemblies. Three centraliser joints are added into the riser string positioned near the bottom, centre and top of the buoyancy cans.


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Waveform joint The last joint within the riser string is a waveform joint that provides for riser space-out using adjustable slips in the surface wellhead. Once the riser is locked to the seafloor wellhead and tensioned, the proper wellhead is determined and the waveform slips are set. The landing ring, which is previously attached to the buoyancy can stem is stroked upward using the adjustable riser support structure and attached to the surface wellhead. The remaining waveform joint above the wellhead is removed and a seal assembly installed. A clamp hub and seal pocket at the upper end of the wellhead is used for attachment of the tubing spool. Tubing spool A tubing spool is attached to the wellhead that provides an internal bowl for tubing hanger support, sealing and lock-down. The upper end of the tubing spool has a clamp hub for attachment of either the surface tree or blowouts preventer spool. The hanger supports dual CRA (corrosion resistant alloy) tubing strings that run through the riser and lock into a packer located below the seafloor wellhead. A control umbilical strapped to the tubing strings provides riser annulus dewatering, subsurface safety valve control, and chemical injection. III.

Steel Catenary Riser (SCR)

Steel Catenary Riser is essentially an extension of the pipeline, suspended in a near-catenary shape from the platform to the seafloor (similar configuration as depicted in figure 15). The SCRs are composed of steel pipe sections welded endto-end, terminating at a flexible joint which is supported by a receptacle mounted on a support frame (see figure 5 in chapter 3 “Interface requirement”). Deck piping is connected to the steel riser by means of a flange connection mounted on top of the flexible joint. The entire riser has a triple coat epoxy/polyethylene coating for corrosion protection, abrasion resistant coating is also required in the touchdown area. The upper 150m have neoprene coating for additional protection and marine growth prevention, plus triple start helical strakes for suppression of vortex induced vibration. The lower section of riser resting on the seabed could be anchored as required to minimise the horizontal displacement and to prevent excessive pull on connection point to sealine when the floating production platform is in far position. The Flexjoint technology (see figure 5) which accommodates the riser motions at the platform has made the steel catenary riser possible. Steel catenary risers, used for oil and gas export, have been successfully deployed on the Shell Auger TLP ( 2 x 12" in 870m WD), Shell Mars TLP (1 x 14" and 1 x 18" in 950m WD) and British-Borneo Morpeth Mono-column TLP (518m WD) in the Gulf of Mexico. The world's first steel catenary riser to be used in conjunction with a semisubmersible based floating production system has just been installed by Petrobras on floater P18 in 910m WD Marlim Field Campos Basin Brazil. This 10" riser will be connected later with flexible lines to the P 26 platform. Following the trend of using steel catenary risers for export lines in Campos basin, Petrobras will install 2 X 12" oil export SCR's on the semi-submersible P 19, at Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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Marlim Field, in a water depth of 770 meters. The platform will be taut leg anchored with 16 polyester/chain lines. The successful installation of this riser is expected to be the next evolutionary step in deepwater production technology for floating production systems, which impose more motions on the riser than on the tension leg platforms. The use of steel catenary riser system on FPSO’ s is still under development with main concern on the fatigue issue due to the ship first order motion characteristics.

IV.

Hybrid Riser Tower

As an alternative to the previous riser systems, the hybrid riser tower appears to be an attractive solution for deepwater applications (see figure 25). The hybrid riser tower concept began with the non-offset configuration implemented on the Green Canyon field in 470m water depth (see section 4.3.2 I., where this type of riser is referred as "top tensioned riser tower applied to semisub"). It was, thereafter refurbished and re-used on Garden Banks in 670m water depth. The offset hybrid riser was then elaborate for the Deepstar Project, to improve the riser tower compliant motions, and this concept was retained for the Girassol field development (West of Africa in 1350m water depth).

Hang-Off platform

FPSO Bending Stiffener 0m

Sea Level -50 m Sub-surface Buoy -50 m

Flexible Risers

-65 m -70 m Bending Stiffener Insulation Foam Central Air Can Jumpers

Gooseneck Steel Line Hang-off Leve

Central Air Can

Riser Tower

Riser Base

-1000 m Suction Piles 150 m -1000 m

Seabed

Figure 25 – Offset hybrid riser tower concept Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The hybrid riser tower system has two unique features: − a “compliant” reaction during the slow drift motion of the FPS, − a versatile concept as the main riser body (neutrally buoyant) can be extended to any required water depth. The concept of the offset hybrid riser tower includes the following main items: • A riser base, anchored on the seabed by means of suction piles and including a connection system to latch the riser tower (i.e. Merlin, Thor or collet connector, Roto-latch, etc.). Flexible or rigid jumpers allow the connection of the sealines to the flowlines contained within the riser tower. • A riser tower, which raises from the riser base to about 70m below the sea level (in order to mitigate the current-waves action on the subsea buoy). This is a bundle composed of steel lines (flowlines, injection and service lines, heating lines, etc.) arranged around a structural member (i.e. the central air can) and contained within buoyancy / insulation foam modules. • A subsea buoy, which provides additional buoyancy to the riser tower in order to improve the dynamic behavior and keep the riser tower in tension whatever are the environmental conditions. The subsea buoy top is located between 50m –100m below the sea level in order to minimise the influence of surface current and waves and to avoid high first order motions. • Flexible risers connecting the tower top assembly to the FPS while allowing relative motions. The riser tower is designed with steel flowlines spread around a central air can. The latter combines both functions of (1) providing additive buoyancy and (2) load resistance by taking tension and bending moment. The flowlines are suspended at the riser tower top level and are free to move axially along the tower due to thermal expansion. Spacers and thrust collars are welded and spread along the riser tower length to guide the flowlines and to transmit the uplift force of the buoyancy modules to the central air can. The subsea buoy is attached to the central can (e.g. by means of a flex-joint) providing uplift force to maintain the top of the riser tower within a desired watch circle under the drag and weight action of the flexible risers, and also the FPS motions. The flexible risers are connected to the upper riser tower connection system composed of connectors and goosenecks. This assembly enables the transition between the upper end of the flowlines spread around the central air can, and the flexible risers.


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A typical analysis method of a hybrid riser tower system is presented hereafter: IV.1. Hybrid Riser System Global Analysis

The analysis is mainly concerned with: •

the hydrodynamic loads induced by waves and current,

•

the relative dynamic offset between the hybrid riser tower and the FPS in both plans (parallel and perpendicular to the FPS longitudinal axis),

•

the dynamic responses of the system: natural frequencies, wave excitation and vortex induced vibration, fatigue,

•

tow to site and the upending analysis of the hybrid riser system to its vertical position.

IV.2. Mechanical Sizing

The mechanical sizing of the flowlines and the central air can is based on burst and hydrostatic collapse analysis. A local buckling analysis will be performed based on the dynamic results in order to check the initial wall thickness evaluation. The lines are not designed against the buckle propagation criterion. Because low bending radii are not expected during installation and production phases. Designing the lines to meet the buckle propagation requirement would be overconservative and would involve higher steel weight, a bigger subsea buoy and therefore higher drag loads on the riser system.

IV.3. Riser Tower Insulation Sizing

Syntactic foam in modular forms are used for the purposes of (1) flowline bundle insulation requirement (U<6 W/m² °K) and (2) buoyancy adjustment of the riser tower through its entire length. The minimum foam thickness is given by manufacturing process, mechanical resistance and insulation considerations. The external diameter of the riser tower and the foam modules is governed by: • the riser tower section arrangement (i.e. the number, the diameter and the repartition of the flowlines around the central air can) • the minimum thickness of foam • the required buoyancy of considerations.

the tower,

especially for

tow stability

IV.4. Subsea Buoy Sizing

The subsea buoy’s net uplift force is dictated by: • static equilibrium of the riser system in production mode with the required tension provision in order to avoid any dynamic compression of the central member. The dynamic analysis will verify that no compression occurs. • Eigen period analysis, as the first natural period of the hybrid riser system is mainly governed by the subsea buoy tension (see the following section for further information on "Eigen-mode analysis"). Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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IV.5. Eigen - Mode Analysis

The Eigen mode analysis is required to prevent the hydrodynamic coupling between the Riser System and the FPS 1st and 2nd order motions. The analysis will consider the 1st and 2nd Eigen periods of the Hybrid Riser Tower. In general, such natural periods would be expected to be: • pendulum mode, parallel and perpendicular to the FPS longitudinal axis • bending mode (2nd Eigen period associated with the first bending mode) The dynamic response can be of two different natures: (1) inertial response governed mainly by the excitation period, and (2) resonant response at a natural period of the system, governed by the existing damping rate. The pendulum resonance mode (i.e. low frequency resonance) can be prevented by a proper hydrodynamic design of (1) subsea buoy tension and (2) flexible riser configuration, to obtain a pendulum frequency higher than the FPS slow drift frequency but lower than the subsea buoy vortex shedding frequency. The riser tower bending mode can be excited in the high frequency range, which can varied from high frequency (flexible riser VIV) to the wave frequency range (e.g. FPS 1st order motion, riser tower VIV). For the subsea buoy, the vortex shedding frequency falls in the low frequency range.


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5

INSULATION TECHNIQUES

5.1

General

Deepwater offshore oil and gas fields are economically developed using subsea completions, where produced fluid may travel a quite long distance, before reaching process facilities on the floating production system. During transport, the produced fluid could cool down to the ambient seawater temperature as low as 4°C or less. Studies and experiences have shown that produced fluid at such a low temperature could cause unacceptable emulsion, hydrate, and paraffin wax deposition problems. The field proven solutions to above problems are discussed below: -

Emulsion: Installation of crude heaters and/or injection of demulsifying agents on the floater could be used to breakdown emulsions, but these alternatives required space, weight and cost on an already congested floating production system.

-

Hydrates: Once again, establishing facilities for continuous injection of methanol or glycol to depress hydrate formation temperatures add burden to the floating production system and increase operating costs.

-

Wax: same impact as above if injection of wax suppressants is implemented.

An insulated flowline (sealine + riser) approach could overcome these problems by keeping the produced fluid temperature above a required temperature for the different operation modes : e.g. 40°C for production mode and 13°C for well testing.

5.2

Selection of an insulation material

The first step in engineering an insulated riser or sealine is to find an appropriate insulation material. Properties and requirements to be considered included thermal conductivity, weight (density), compressive strength, availability, manufacturing technique, attachment methods etc. In order to select the type, and estimate the amount required, a computer program is used to calculate temperature drops in a riser or sealine with a single phased fluid. A variety of cases are then calculated for various flowline lengths, production rates, water cuts, etc. – assuming insulated coatings ranging from different types of insulation material. The selected material should provide sufficient insulation value to meet design criteria, retain its insulation properties in wet environment, resist to installation loads and finally have sufficient compressive strength to keep it from being crushed under hydrostatic pressure encountered in deepwater field development.


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5.3


Insulation material for steel riser and hybrid riser tower

For the growing activities in deeper waters (> 300m) the options are limited to the use of solid materials, special engineered polymer composites and epoxy syntactic with hollow glass or silicate microspheres, that can sustain a water depth of more than 1000m and a temperature of 135°C. Such constructions may be supplied with a thickness of 100mm and a thermal conductivity k=0.1W/m°C, corresponding to a heat transfer U-value of 1.5W/m2°C. The most promising thermal insulation material in deepwater applications are syntactic foams which fall into two groups as described below: −

Pure syntactic foam composed of base polymer as initial constituent with a specific gravity around 1.0 hence the material is almost neutrally buoyant. The density of the polymer is reduced by including large numbers of small hollow glass spheres known as microspheres. The microspheres typically have a diameter of between 100 and 150 microns. Their presence can result in a reduction of the specific gravity to between 0.5 and 0.6. This material is well adapted to rigid steel riser.

−

Composite syntactic foam where a third component known as macrospheres is added to further reduce the material density. Macrospheres are typically hollow thermoplastic spheres with a nominal external diameter of 50mm. Inclusion of the macrospheres can reduce the syntactic foam specific gravity to between 0.3 and 0.4. This thermal insulation material is well adapted to hybrid riser.

The main thermal insulation materials that are normally considered for use with wet insulated steel riser are detailed below in table 3:

Material

Max Water Depth


Density

(m)

(W/m/°K)

(kg/m3)

1800

0.13

830

900 - 1800

0.16

710

Syntactic Foam = epoxy resin + microspheres + macrospheres (CRP)

3000

0.12

500

Test Syntactic Polyurethane (Joint venture project)

2750

0.1

700

Syntactic Tape (also used for flexible lines)

1000

0.11

640

950 - 1070

0.17

750

1000

0.12

No limit (R&D)

0.16

Syntactic Polyurethane + Glass micro-spheres (ISOTUB, BALMORAL, BPCL) Syntactic Polypropylene (ISOTUB)

Multi-layer Polypropylene Insulating Elastomer Thermoplastic Rubber

1029

Table 3 – Thermal insulation material for steel and hybrid riser


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5.4


Insulation material for flexible riser

It should be stressed that the thermal insulation properties of a typical flexible production riser are extremely good in comparison with those of a wet insulated rigid pipeline, due to its multiple plastic layers. However, in some instances, where the temperature loss along the riser must be kept to a minimum, the thermal insulation of a typical flexible riser is not sufficient. Several methods are available in order to increase the thermal insulation properties of a flexible riser. The main methods used at present are: -

Increasing the thickness or changing the material of the thermoplastic layers (double internal thermoplastic sheath, double external thermoplastic sheath).

-

Using a special thermal insulation design based on coiling Cofoam material around the pipe. Cofoam (about 1500 kg/m3) is an extruded semi-rigid polyvinyl chloride (PVC) foam (see figure 26).

-

Using tape wound on the pipe and composed of hollow glass microspheres, in the size range of 100-200 microns, fibreglass macrospheres 0.124-0.5 inches in diameter and an epoxy, polypropylene, or polyester resin binder.

Cofoam layer

Figure 26 – Thermally insulated flexible pipe


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It should be noted that the Coflon (thermoplastic material used in flexible riser to cope with high temperature produced fluid) has a lower thermal conductivity than Polyamide which in turn has a lower thermal conductivity than high density polyethylene. The thermal conductivity coefficient of these thermoplastics is very low: -

K Coflon = 0.16 Kcal/m.h.°C at 34°C and 0.14 Kcal/m.h.°C at 104°C

-

K Cofoam (Carizite) = 0.13 Kcal/m.h.°C at 70°C

-

K Polyamide 11 = 0.288 Kcal/m.h°C (between 50 and 100°C)

-

K High density polyethylene = 0.35 Kcal/m.h.°C at 20°C

For 6-8 inch ID flexible riser, a typical heat transfer coefficient U-value of 1.5-2W/m²K can be achieved with "Carazide" (or Cofoam) insulation material. Please refer to chapter “Insulation techniques” in "Sealines" Document (Reference 7) for further information on thermal insulation material applied to deepwater flowline.


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6

HEATING TECHNIQUES

6.1

General

Heating technique, considered as active subsea insulation method, is viewed as a key technology for flow assurance as the industry moves into increasingly deep waters. This will help to reduce the risk of hydrates and wax plug formation when production lines are shut down while at the same time reducing the risk of environmental contamination through leakage of chemicals currently injected into the lines as a preventive measure. The heating techniques may be designed for the following purposes: -

To maintain steady state pipe temperature above the hydrate formation temperature (typically 15-25°C) after planned or non-planned shutdowns. The objective is to start the system prior to hydrate formation - Heating of the pipe, which have been cooled down to the ambient seawater temperature. This situation might be valid after the unlikely situations of either a very long major electric power system shut-down, > 10 hours, or after a simultaneous process shut-down and heating system failure - The system could also be used to maintain the required temperature at low production rates. The rating of a heating system is dependent on many factors. These might be material or operational parameters, or design criteria. The following parameters are essential for the design of the heating system:

6.1.1

Pipeline -

Material/composition thermal data

-

Dimensions: diameter/thickness

-

Riser insulation: dimensions (thickness), thermal conductivity (with corresponding U-value and heat capacity)

-

Thermal data and dimensions of protection on the riser section resting on the seabed (surrounding/seabed, including depth of gravel, rock dumping, etc.)

-

Thermal properties of the pipe content in different operation modes

-

Geometry/length of riser


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6.1.2


Design criteria -

Temperature of seawater

-

Sea depth

-

Steady state temperature

-

Required heating time

-

Required melting time

At present, the main techniques proposed by manufacturers to heat up risers are listed below: -

Electrical heating applicable to thermally insulated rigid steel risers

-

Hot water circulation heating applicable to flexible and rigid steel risers

6.2

Electrical heating

The following techniques based on electric heating may be used: -

Electric heating cables

-

Electromagnetic induction heating

-

Direct electric heating

Refer to chapter “Heating techniques” in "Sealines" Document (reference 7) for further information on electrical heating systems. In all three methods, electric heat is used to maintain or raise the pipe temperature above the critical value for hydrate (typically 15-25°C) or wax formation (typically 20-40°C). The induction heating system has previously been qualified for a specific installation at a full scale test installation in 1992 (Statoil/EFI Combipipe). It is technically an efficient method, but the comparatively high installation cost makes it normally more expensive than a direct heating system. The "SECT (Skin Effect Current Tracing) heating system", where the electric cable is located in a small steel pipe welded to the well stream pipe, is applicable only for short pipeline lengths. This section will therefore only cover the most promising and cost effective solution to heat up steel risers i.e. direct electric heating which was qualified for the Asgard and Huldra projects.

6.2.1

Direct Heating System description

The direct heating system, developed for thermally insulated rigid steel pipe, is based on the fact that an electric alternating current in a metallic conductor (i.e. cable/pipe etc.) generates heat. In the direct pipe heating system the pipe to be heated is an active conductor in a single-phase electric circuit, together with a single core power cable as the forward conductor, located in parallel with and close ("piggy-back") to the heated pipe (see figure 27). The heating system is supplied from the FPS power supply by means of two power cables. One of the two single core cable is connected to the near end of the pipe, and the other to the forward conductor which is connected to the outmost end of the pipe.


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Power Cable Straps

a/ Topside Power Supply

b/

Thermally Insulated Pipe Power Supply Cables

Connections

Power Supply "Piggy-Back"

Current Transfer Zone Anodes On Pipe

Well Stream Pipe

Connection

Current Transfer Zone Anodes On Pipe

Figure 27 – Direct electric heating principle For safety and reliability reasons, the heating system is electrically connected ("earthed") to surrounding seawater through several sacrificial anodes for a length of approx. 50m at both ends where the cables are connected. The following results can be drawn from the qualification test performed on 8-12" single rigid steel pipe: -

No problems are foreseen for the concept on pipe dimensions up to 20"

-

The typical power requirement is 100-150W/m

-

The restriction concerning cable insulation level (36kV) limits the length of heated pipeline to 50km

-

No corrosion on normal carbon steel or 13%Cr steel pipes caused by the electric heating system is observed during qualification tests


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6.3


Hot water circulation heating

For small to medium diameter risers requiring low heat compensation, the circulation of hot water can be a cost effective and reliable alternative to the electric heating in deepwater applications. The hot fluid circulation heating system consists in flowing hot water in external lines circumferentially installed on production risers (see figures 28 and 29). The water is injected from the floating production system and dumped to sea (i.e. to save a return line). Hot water line Upper intermediate sheath layer

Lower intermediate sheath layer Production line

Plastic filler

Figure 28 – Hot water heated flexible riser

Insulated buoyancy module

Hot water line

Production line

Central can

Gas lift line

Gas injection line

Water injection line

Figure 29 – Hot water heated production lines in hybrid riser tower The heating lines are either in coiled tubing pipes or flexible pipes dependent on riser design criteria. The diameter and number of the heating lines will mainly depend on the dimensions of the riser to be heated up and the temperature variation between seawater and the produced fluid for different operation modes. The heat transfer value between the heating lines and the production riser to be heated is low, but it can be improved by either creating a heating chamber with thermal insulation material or using a conductor material placed between them.


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7

VORTEX INDUCED VIBRATIONS

7.1

General

The vortex vibrations are induced by a fluid flow acting on cylinder elements (i.e. vibrations due to vortices, see section 7.2) and forcing them to vibrate by exciting their closest eigen mode (i.e. mode shape associated to natural frequencies of the pipe closest to the vortices oscillation frequency). Mainly the rigid pipe riser systems are associated to the VIV problem. The high inertia value of the rigid pipes involves high natural frequencies, which correspond to the VIV excitation periods. But even risers made of flexible pipe, which have large structural damping, can experienced VIV, although the consequences are quite minimal and thus are not a real concern. VIV generally does not induced high stresses in the rigid pipe riser, but it is damageable to the system as it reduces its fatigue life by inducing high cyclic loads.

7.2

VIV prediction

The VIV prediction is a complex subject, especially for deepwater riser systems. This vibrating phenomenon can be basically described as follows: -

The riser, immersed in a fluid flow, creates vortices; the two separation points (see figure 30) oscillate on the riser sides, thus creating forces that oscillate at the vortex apparition frequency. There are two types of oscillation: (1) oscillation in-line with the velocity motion and (2) oscillation perpendicular to the velocity vector.

Flow

Flow separation points

Figure 30: Fluid flow sketch -

This vibrating phenomenon becomes critical when the cross flow force frequency is relatively close to one natural period of the riser. This phenomenon called “lock-in” occurs (i.e. pipe oscillates at its natural frequency which is closest to the excitation induced by the vortices) which can result in serious damage by reducing the fatigue life of the system.


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Predicting VIV and estimating response amplitude and frequencies are key issues when determining the fatigue life of a riser system. The difficulty in predicting VIV occurrence and effects is due to: -

Uncertainties about the environmental conditions that will be encountered by the riser system, especially current profiles (magnitude and shape variation with depth).

-

The inability to fully understand and model the fluid-structure interaction.

-

Lack of full scale response data; the VIV prediction formulae are based on empirical coefficients which are not well defined as they were determined for some particular cases and often in laboratory conditions. These empirical coefficients are highly dependent on several parameters such as the riser system data (diameter, length, shape of the riser, marine growth, etc.) and the environmental conditions (i.e. current profile).

-

Multiple mode VIV that may occur due to the current profile variations with depth, several natural bending modes may be simultaneously excited into VIV (i.e. the riser experienced different frequencies of excitation with depth).

-

The presence of adjacent riser, which modify the fluid flow and create shedding.

Some verification rules and methods are recommended by classification societies or institutes supplying with regulations and codes (such as DnV, API, etc.). These methods are based on simplified formulae, which allows quick verifications and estimations but are generally conservative. Programs are also available to help in VIV occurrence and effect prediction. The most widely used is the MIT program SHEAR7. It was initially developed to model straight risers. Current versions are also able to perform runs with other structure models, such as catenary, by utilising hybrid techniques (i.e. equivalent model calculated by a finite element program, can be read in file data form); the program limitations for catenary shapes introduce uncertainty.


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7.3


Vortex suppression devices

If potential VIV effects are detected during the engineering phase of a riser system, one of the two following solutions may be used: -

Either redesign the riser by modifying the tension, changing its mass or designing another configuration. This solution is generally costly and may have repercussions on the production floater.

-

Or add vortex suppression devices.

The main VIV suppression devices are: •

Helical strakes

•

Fairings

•

Perforated or axial rod shrouds

•

Splitter plates

SPLITTER PLATE HELICAL STRAKES

PERFORED SHROUD

FAIRINGS

AXIAL ROD SHROUD

Figure 31: Main VIV suppression devices


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The most popular devices are the helical strakes and the fairings. Weathervaning fairings are for example used in the Gulf of Mexico on the Shell Mars TLP risers, while helical strakes equipped the export steel catenary risers of Auger. Both strakes and fairings can dramatically reduce VIV fatigue damage (by over 80%) but introduce intrinsic disadvantages: -

Both complicate the installation phases as the equipped riser system is difficult to handle.

-

Strakes increase the riser drag, which is detrimental to the riser behaviour, and require a continuous coverage of the VIV sensitive length.

-

Fairings can reduce drag loads and only require a partial coverage of the critical length of the riser, but they need to rotate with current direction, which is a great disadvantage for long-life utilisation, as efficient anti-fouling devices are required to avoid their gripping by marine growth.

Figure 32: VIV helical strakes


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8

ARTIFICIAL LIFT REQUIREMENT

8.1

General

Artificial lift is required when the natural reservoir pressure is insufficient to lift the produced fluids to surface at economic production rates. This can occur in the event of water breakthrough at the wells (increasing the weight of the liquid column), low pressure at the reservoir or the production of low GOR heavy crude. Artificial lift also helps to stabilise the fluid flow regime, and hence eliminate slugging in the production riser. Artificial lift may be a cost effective solution to develop satellite fields as it facilitates the transportation of produced fluids over longer distances, thus reducing the investment by simplifying the production layout and reducing the number of platforms. Furthermore, it increases field life and recovery rate. The offshore oil and gas production is typically based on natural flow driven by reservoir pressure, water injection and artificial lift, whenever necessary. The flow rate requirement on top of the production riser is formulated as follows: WP – TPD – HP – TRP > 0 Where:

WP = Wellhead Pressure TPD = Total Pressure Drop in Wellhead, Sealine and Riser HP = Hydrostatic Pressure = ρgh (ρ effluent density along fluid column) TRP = Required Top Riser Pressure

Or, in the case of Riser Artificial Lift: BRP – HP – RPD - TRP > 0 Where:

BRP = Bottom Riser Pressure HP = Hydrostatic Pressure = ρgh (ρ effluent mixture & gas density along riser) RPD = Riser Pressure Drop TRP = Required Top Riser Pressure

In this formula, two terms can be adjusted to improve the flow rate: -

The Bottom Riser Pressure, which can be increased by adding a pump unit The transported fluid density ρ along the riser, which can be reduced by gas injection. The lower is the injection point, the better is the lightened effect. Therefore, the injection point should be positioned close to the riser base.


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THE FIRST METHOD CALLS FOR ELECTRICAL SUBMERSIBLE PUMPING TO PERFORM THE ARTIFICIAL LIFT WHEREAS THE SECOND FOR GAS INJECTION. Product Flow Condition BRP – (ρgh) – RPD - TRP > 0

Pumping

Gas Lift

BRP > (ρgh) + RPD + TRP

ρ < (BRP – RPD – TRP)/gh

THE DIFFERENT ARTIFICIAL LIFT METHODS ARE LISTED BELOW: The different artificial lift methods are listed below: -

gas lift

-

electrical submersible pump

-

hydraulic jet pump

-

progressing cavity pump

-

multiphase pump

-

subsea separation system

The following covers only the gas lift method (i.e. the most cost effective solution) applied to rigid or flexible riser and hybrid riser tower having the gas injection point at the riser base.

8.2

Gas Lift Method

The gas lift method principle is to increase the flow rate by reducing the specific gravity of the producing fluids. For subsea application only gas lift has been widely used as artificial lift method, due to its intrinsic similarity with onshore' s gas lift method. This similarity comes from the fact that it is driven by a power fluid using roughly the same components for both onshore and subsea application. For this reason, gas lift is today seen as the subsea conventional artificial lift method. Sometimes, gas lift may not be the best method to fit specific field's requirements. This happens, for instance, when there are long distances between well heads and the host platform system, and the gas injected, even though helping the flow in the vertical sections (well and riser), increases pressure drops in the horizontal section of the flowline. Additionally, this method demands compressors and an increase of gas facilities to handle the extra recycling gas, with consequent drawbacks on platform weight and space requirements, which have a high impact on offshore installation costs. Other problems with the gas lift method are its contribution to the cooling of the producing fluid due to the gas temperature and expansion (Joule-Thomson effect) and a relatively low efficiency (i.e. a ratio between output and input hydraulic power of about 20%). The cooling of the produced fluid will aggravate the wax and hydrates formation problems. The gas lift method hence requires to be early integrated in the riser design as a part of the riser system; this is especially true for concepts such as riser bundle or hybrid tower. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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No difficulties, regarding the riser system definition, are expected when using the conventional gas lift method; the only requirement is the provision of a sufficient number of gas lift line. But an activated riser configuration requires additional studies, mainly due to the lack of experience. As the injection point is positioned on the lower part of the riser, special studies must be conducted to precisely define the required equipment (valve, gas diffuser, etc.) and the consequences on the riser structure (reinforcement to increase high stress and fatigue resistance) and behaviour. The gas lift method is characterised by two modes: -

Internal mode: In this mode the gas lift method uses coil tubing introduced from the top of the riser to the riser base or gas lift lines circumferentially arranged around the riser (e.g. integrated flexible riser)

-

External mode: In this mode, each production line has its own gas lift line clamped to the outside diameter. The production lines can also be activated by a common gas lift line through the subsea manifold

8.2.1

Internal gas lift using coil tubing

The artificial lift is performed by means of a coil tubing deployed from the inside of the production riser at the surface (see figure 33). This method is well adapted to flexible and rigid riser. The gas injection point can be selected by adjusting the length of the coil tubing. This solution requires one coil tubing per riser, which can also be used for the chemical injection.

Produced fluid + Gas

Gas injection

Riser

Coil tubing

Sealine

Produced fluid

Figure 33 – Gas lift through coil tubing


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The advantages and disadvantages of this solution are summarized in table 4: ADVANTAGES

DISADVANTAGES

- Possibility to adjust the injection point to the production type (specially during start up) - No requirement for thermal insulation on gas lift lines (i.e. gas remains at effluent temperature as there is no contact with sea water) - No interaction with the environment loads on the production line

- Recovery of coil tubing before pigging - Difficulty to study the dynamic behavior of both lines (vibration of gas lift line, potential wear by friction, requirement for centring devices, etc.) - Flow section reduced by the presence of the gas lift line - High cost due to coil tubing unit and deck space - Not applicable to hybrid riser

Table 4 – Advantages & disadvantages summary table 1

List of main equipment is provided in table 5: SURFACE EQUIPMENT - Gas compressor

SUBSEA EQUIPMENT - Production riser

- Gas injection control system - Coil tubing unit Table 5 – Main equipment list 1


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8.2.2


Internal gas lift lines integrated to production riser

In this method the artificial lift is performed by means of gas lift lines surrounding the production riser. The bottom end terminations of the gas lift lines are connected to isolation valve (s) controlled from the surface for safety reasons (see figure 34). This technique is well adapted to flexible risers (i.e. Coflexip Integrated Pipeline Bundle).

Gas injection


Riser

Gas lift line

Sealine

Cross section view Produced fluid

Figure 34 – Gas lift line integrated production riser The advantages and disadvantages of this solution are summarised in table 6: ADVANTAGES

DISADVANTAGES

- Standard installation method - No interference with pigging or coil tubing operations - No requirement for thermal insulation on gas lift lines - No interaction with the environment loads on the production line

- Increase drag and VIV due to larger external diameter - Increase tension load during laying operation and at hang off platform - Requirement for specific tensioners - Flexible technology to be qualified for deep waters including manufacturing process - Technical and economic limitations to small production risers (ID = 6"-8") - High purchase cost

Table 6 – Advantages & disadvantages summary table 2


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List of main equipment is provided in table 7: SURFACE EQUIPMENT

SUBSEA EQUIPMENT

- Gas compressor

- Production riser : 6 or 8 inch

- Gas injection control system

- Gas lift lines : ½ - 3 inch - Umbilical line - Surface controlled isolation valve (s) - Gas diffuser head

Table 7 – Main equipment list 2

8.2.3

External gas lift line

The artificial lift of the produced fluid is made using gas lift at the riser base. The gas injection is performed from the surface to each production riser through a dedicated line. Several solutions can be considered for the installation of the gas lift line: -

Externally mounted on each production riser using the piggy back method (see figure 35). - Inserted in the thermal insulation of the production riser. -

Clamped to the central member of the hybrid riser.

This technique is applicable for all type of risers. Gas Injection

Produced Fluid + Gas

Riser Gas lift line

Sealine Produced Fluid

Figure 35 – Gas lift line in piggy back Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The advantages and disadvantages of this solution are summarized in table 8: ADVANTAGES

DISADVANTAGES

- Surface control of the gas injection

- Increase drag

- No interference with pigging or coil tubing operations

- Longer installation time (two lines)

- Applicable to most type of risers - Complete independence between production and gas lift lines

- Requirement for thermal insulation on both lines - Dynamic behaviour of lines may impact on clamps (fatigue, wear, etc.)

- Configuration well adapted to coil tubing pipe technology - Low cost solution

- Critical injection point requiring detailed engineering

- Lower operation and maintenance cost Table 8 – Advantages & disadvantages summary table 3 List of main equipment is provided in table 9: SURFACE EQUIPMENT

SUBSEA EQUIPMENT

- Gas compressor

- Production riser : 6 or 8 inch

- Gas injection control system

- Gas lift lines : ½ - 3 inch - Umbilical line - Surface controlled isolation valve (s) - Gas diffuser head



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8.2.4


External common gas lift line

In this configuration, the gas injection point is also at the riser base. The gas is routed from the surface to a retrievable subsea manifold through a common gas lift line. The gas distribution is then made using hard piping or jumpers connecting the subsea manifold to the production riser (see figure 36). Gas injection


Gas lift line

Riser

Sealine

Produced fluid

Gas lift subsea manifold

Figure 36 – Manifold based gas lift method An alternative to the above solution consists to gather all gas lift lines together in a multi-bore line, which will be distributed at the riser base for the gas injection in the production risers. In the first alternative, the gas injection is controlled from the surface by means of electrohydraulic umbilical connected to the subsea manifold, whereas in the second solution, the control is done directly from the surface. This technique is applicable for all type of risers. The advantages and disadvantages of this solution are summarised in table 10: ADVANTAGES

DISADVANTAGES

- Limited number of lines to be installed

-

- Surface control of the gas injection - No interference with pigging or coil tubing operations

- Requirement for thermal insulation on both lines

- Applicable to all type of risers

- Number of production risers limited to subsea manifold and gas lift line capacity

- Complete independence between production and gas lift lines Configuration well adapted to coil tubing pipe technology

Well adapted for compact riser configuration

- High number of subsea connections

- Requirement for subsea foundation to support all subsea equipment -

Low flexibility in operation and maintenance

- High cost solution Table 10 – Advantages & disadvantages summary table 4 Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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List of main equipment is provided in table 11: SURFACE EQUIPMENT - Gas compressor - Gas injection control system

SUBSEA EQUIPMENT - Production riser : 6 or 8 inch - Gas lift line: 8 or 10 inch for common line and 2 or 3 inch for multi-bore line - Retrievable subsea manifold - Umbilical line - Choke valve (s) or isolation valve (s) - Gas diffuser head (s)



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9


9.1

General

Selection of methods for installing hybrid, flexible or metallic risers is strongly dependent on field development type, vessel capability and availability, and riser material. The following table 12 illustrated the installation techniques that can be considered depending on the type of riser:

TYPE

INSTALLATION TECHNIQUES VESSEL REQUIREMENTS

Non-offset hybrid riser

Conventional drilling riser running 1. Drilling and/or production vessel techniques and equipment (TLP, Semi-submersible, Spar)

Offset hybrid riser

Surface or Controlled Depth Tow 1. Leading Tug Method + Upending and flexible 2. Trailing Tug jumper connection operations 3. Survey vessel 4. Combined flexible lay jumper connection vessel

Flexible riser

J lay with tensioners

and

1. Installation vessel equipped with J lay ramp and tensioners, or a dedicated flexible lay vessel

2. Survey vessel Metallic riser (e.g. SCR) 1. J lay with tensioners or collar 1. Lay vessel hang off points

2. Survey vessel

2. Bottom tow technique + 1. Leading Tug erection operation 2. Trailing Tug

( 2 x dual 10" insulated flowline 3. Survey vessel in 418m WD on BP Troïka) Table 12 – Installation techniques: Summary table

The installation techniques for flexible and metallic risers are further discussed below.


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9.2


Installation of flexible risers

Vessels equipped with dynamic positioning (DP) system, which allows accurate tracking of laying routes, should preferably carry out the installation of flexible flowlines. The DP system ensures station keeping with selection of optimum heading enables a close approach to floating production systems and eliminates the risks of damage to pipe by anchors in congested areas. In addition, the ideal vessel should have a large pipe and/or cable carrying capacity. As with any type of offshore installation work it is imperative that the installation vessel and its equipment are suitable for the handling of the flexible product. In the case of riser installations, the number of risers and their configuration will dictate the vessel requirements. For example, a free hanging riser system is the simplest to install due to the absence of additional hardware components. A specialised DP vessel equipped with a J lay ramp with tensioners or vertical laying spread is usually perfectly adequate. The S systems, Steep S and lazy S, consists of components such as buoyancy tanks, arches and riser bases. The installation vessel will require a crane with sufficient capacity, height and outreach to allow for the over-boarding operations, while controlling the catenary lay radius at the seabed sag-bend. Depending on the physical size of the riser system (riser diameters, arches and buoys overall dimensions) a vessel with an A-frame may also be used for a lazy S installation. Deck space and payload are also important considerations for both systems. The Wave systems, Steep, Lazy and Pliant are often used for single well developments or export systems. Utilising less bulky hardware components, wave systems require lighter crane capacity and less deck space than the S systems. In deep waters, the installation of flexible risers required the mobilisation of DP vessel equipped with a Vertical Lay System, which is composed of a vertical derrick, a gutter, an A&R winch, tensioner (s) and hang off/working platform. This equipment is typically located over the moonpool or at the stern of the vessel (i.e. CSO Sunrise 2000).


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The simplified installation procedures of the different riser configurations are described hereunder:

9.2.1

Flexible riser in “Free hanging” configuration

Lay vessel FPS

4

1

LOWERING OF RISER 1st END EXTREMITY

LAYING VESSEL POSITIONNING

Messenger line

2

Flexible riser

CONNECTION OF MESSENGER LINE

5

RISER TRANSFER TO FPS

Lay direction

3

RECOVERY OF MESSENGER LINE

6

LAYING OF FLEXIBLE RISER

Figure 37 – Main installation phases of flexible riser in free hanging configuration


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A typical installation procedure would consist of the following phases (see figure 37): 1 – 3. A messenger line is passed from the floating production facility to the installation vessel 4.

The upper end of the riser is transferred from the installation vessel to the FPS with the upper section of the riser

5.

The upper end of the riser is secured to the riser hang off platform by means of clamp

6.

The flexible riser is paid out from the lay vessel until reaching the touch down point.

Once the touch down point is confirmed by means of ROV, the flowline is laid in the direction of its final destination


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9.2.2


Flexible riser in “Lazy S” configuration

Lay vessel

FPS

1

LOWERING OF THE MESSENGER LINE

2

TRANSFER OF THE FLEXIBLE 1st

4

LOWERING OF THE DEAD WEIGHT AND LAYING OF THE FLEXIBLE RISER

END EXTREMITY TO FPS

Mid-water arch

Flexible riser

3

LAUNCHING OF THE MID-ARCH

5

FINAL CONFIGURATION

Figure 38 – Main installation phases of flexible riser in Lazy S configuration


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A typical installation procedure would consist of the following phases (see figure 38): 1.

A messenger line is passed from the floating production facility to the installation vessel

2.

The upper end of the riser is transferred from the installation vessel to the FPS with the upper section of the riser

3.

The mid-water arch is launched and positioned at mid-depth by means of the dead weight while paying out of the riser continues

4.

The retaining swivel is disconnected from the mid-water arch and the lower end of the riser is laid on the sea bed

5.

The flowline is laid in the direction of its final destination


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9.2.3


Flexible riser in “Lazy Wave” configuration

Lay vessel FPS

1

LOWERING OF THE MESSENGER LINE

Transfer line

2

TRANSFER OF THE RISER 1st END EXTREMEITY TO THE FPS

4

Buoyancy modules

Flexible riser

3

ATTACHEMENT OF BUOYANCY MODULES AS LAYING PROCEEDS

5

FINAL CONFIGURATION

Figure 39 – Main installation phases of flexible riser in Lazy Wave configuration


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A messenger line is passed from the floating production facility to the installation vessel

2. 3.

The upper end of the riser is transferred with the upper section of the riser The buoyancy modules are attached to the riser as laying proceeds and launched

4.

The installation of the riser continues by the paying out of the riser

5.

The flowline is laid in the direction of its final destination


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9.2.4


Flexible riser in “Steep S” configuration

Lay vessel

FPS

1 LOWERING OF THE MESSENGER LINE

4

LAUNCHING OF MID-WATER ARCH AND DEADWEIGHT

5

DEAD WEIGHT POSITIONNING

Transfer line

2

TRANSFER OF THE RISER st

1 END EXTREMEITY TO THE FPS

Flexible riser

3

PAY OUT RISER

6 TRANSFER TO THE RISER BASE

Mid-water arch

Riser base

7

CONNECTION TO THE RISER BASE

Figure 40 – Main installation phases of flexible riser in Steep S configuration


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A messenger line is passed from the floating production system to the installation vessel

2. 3.

The upper end of the riser is transferred with the upper section of the riser The upper end of the riser is connected to the floating production system while paying out of the riser continues

4.

The mid-water arch and the dead weight are launched

5.

The dead weight is positioned at a predetermined location. The riser may be abandoned at this stage for further connection

6.

The lower end connection is positioned relative to the riser base by means of a come-along (or pulling line)

7.

The lower end connection is tied-in to the riser base


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9.2.5


Flexible riser in “Steep Wave” configuration

Lay vessel Messenger line

FPS

1

LOWERING OF THE FLEXIBLE RISER END EQUPED WITH CONNECTOR

4

LAYING VESSEL POSITIONNING

Buoyancy modules

Pulling line

Flexible riser

2

ATTACHMENT OF BUOYANCY MODULES AS LOWERING PROCEEDS

5

TRANSFER OF THE PULLING LINE

6

RISER HANG-OFF PERFORMED

Riser base

3

CONNECTION TO THE RISER BASE

Figure 41 – Main installation phases of flexible riser in Steep Wave configuration


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Lowering of the flexible riser and its automatic connector (vertical entry) at the stern of the installation vessel.

2. 3.

Installation of the buoyancy modules at adequate locations on the flexible riser. The flexible riser and its automatic connector is directed towards the riser base by means of ROV. Perform automatic connection of the flexible riser onto the riser base by means of ROV.

4.

Paying out of the remaining part of the flexible riser and the vessel takes its position for the transfer of flexible riser to the floater.

5.

On completion of messenger and pulling lines recovery, connect the pulling line to the pulling head mounted on the flexible riser and start the transfer ot the flexible riser to the floater. Once load transfer is completed, recover A&R cable, resume pulling the flexible riser and secure it to the hang off platform.

6.


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9.2.6


Flexible riser in “Pliant Wave” configuration

Lay vessel

FPS

Buoyancy modules

Subsea tree

1

Dead weight

INITIATION AT SUBSEA STRUCTURE

4

TRANSFER OF RISER TO THE FPS

Securing sling

2

5

CONNECTION OF THE TAUT LINE

PULL-IN OF THE RISER 2nd END EXTREMITY

Flexible riser in final position

Transfer line

3

POSITIONING OF THE LAYING VESSEL

6

FINAL CONFIGURATION

Figure 42 – Main installation phases of flexible riser in Pliant Wave


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The first end of the flowline is initiated at the subsea structure and the flowline is laid in the direction of the dead weight.

2.

Installation of the clamp/attachment line sub assembly and the buoyancy modules at adequate locations on the flexible line Perform the connection of the attachment line to the dead weight by ROV

3.

Recover flexible line to surface to form the loop before resume paying out flexible in the direction of the floater

4.

A messenger line is passed from the floating production system to the installation vessel for the transfer of the pull in cable.

5.

Once the pull in cable is connected to the pull in head mounted on top of the riser, the second end of the riser is lowered with the A&R cable.

6.

On completion of the load transfer and disconnection of the A&R cable by ROV, the second end of the riser is pulled in I or J tube then secured to the hang off platform.


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9.3

Installation of metallic risers

9.3.1

General

Outwith the conventional drilling riser running techniques used for the deployment of top tensioned riser from semi-submersible, TLP and Spar, the two most promising installation techniques for metallic risers are J-lay and tow-out. The other methods involving plastic deformation of welds and pipes may affect fatigue life of metallic risers (e.g. reeling, S-lay, combination horizontal firing line and vertical lay, etc…). Another reason restraining the use of these installation techniques is the requirement for wet thermal insulation on metallic risers due to roller friction on risers, which may damage thermal insulation coating. The installation techniques for metallic risers are described hereafter:

9.3.2

J lay technique

The main advantages of J-lay technique are: -

Increased water depth capability Reduced weather sensitivity

-

Reduced pipe stresses and lower tension due to steeper pipe departure

-

Easier start-up, termination and abandonment & recovery operations

-

Reduced complexity attaching buoyancy and ballast during lay

-

Lower horizontal thrust requirement (compared to S-Lay) allowing the use of DP vessel

During J-lay, pre-welded pipe strings consisting of 1 to 6 pipe joints (each approx. 12m long) are welded to the riser, which is clamped on an inclined lay ramp. Pipe joints are welded together, NDT tested and coated before leaving the working platform at a defined angle. The simplified installation procedure of a steel catenary riser with second end transferred to the floater is illustrated in figure 43:


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Lay vessel

FPS

Pulling line

1

RISER LAYING AND VESSEL POSITIONING

4

A&R cable

Steel riser

2

LOWERING OF THE RISER 2nd END EXTREMITY

CONNECTION OF THE TRANSFER LINE TO THE MESSENGER LINE

5

TRANSFER OF THE RISER

Hang off platform

Steel catenary riser Sealine

Messenger line

3

RECOVERY OF THE MESSENGER LINE

6

FINAL CONFIGURATION

Figure 43 – Main installation phases in steel catenary riser


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A typical installation procedure would consist of the following phases: 1.

When the pipelay vessel is about 130m away from the floating production platform, a messenger line is lowered from the floating production system.

2.

A transfer line is lowered from the pipelay vessel at the same water depth to allow ROV to connect the transfer line to the messenger line.

3.

When the messenger line reaches the working platform of the pipelay vessel, it is connected to the pulling head on top of the flexjoint welded to the steel riser.

4.

The steel riser is lowered below the vessel on the pipelay's abandonment and recovery cable until the riser starts swinging over towards the floating production system

5.

After disconnection of A&R cable by means of ROV release hydro-acoustic shackle, a pull-in, run from hydraulic winch on the platform, is used to finally pull the riser into the receptacle.

6.

The pipeline is then free flooded, the spool piece that connects the riser to preinstalled hull piping is installed and the pipeline system is ready for final testing.

9.3.3

Tow out method

Tow out is an alternative method of installing metallic risers. This necessitates onshore fabrication of the riser, followed by surface, sub-surface or near-seabed tow to the offshore site. The tow out has the advantage that the riser can be inspected and tested before it is towed out.

This technique followed by an upending operation has been proposed for the installation of the hybrid riser tower on Girassol project. The installation of a hybrid riser tower is subdivided into three phases (see figure 44): The tow out from the onshore fabrication site where the riser tower is assembled and tested. The upending operation The connection of the tower to the riser base Leading Tug

Hybrid riser tower in subsurface tow

Buoyancy Modules

Spar Buoy

Trailing Tug

1

Sea Level

0m

2

Leading Cable Trailing Cable 3

Riser Tower in vertical position 4 5

Acoustic Release Shackle

Riser Base

-1000 m

Seabed

Figure 44 – Main installation phases of hybrid riser tower (sub-surface tow) Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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The flexible risers are installed and connected at a later phase, after the FPSO has arrived on site. The flexible jumpers could be either "pre-installed" at the onshore site or subsea installed. The tow out operation consists in bringing the tower on site by towing it with the help of leading and trailing tug (assisted by a survey vessel). The tower is supported by means of subsurface and surface buoys, while its own weight is adjusted by temporary flooding of some flowlines. Once on site, the up-ending operation is performed. The tugs apply the adequate tension to prevent any excessive bending while the buoys are removed. Two up-ending alternatives can be considered: −

the controlled riser bottom end lowering, with the help of the trailing tug (quasi static method).

−

or the "free-fall" upending method.

The leading tug and the Sub-surface Buoy will control the riser tower top position. Monitoring of tension and curvature of the riser tower is performed continuously during the operation by the survey vessel using acoustic transponders installed on the riser tower. On completion of the up-ending operation, the riser tower is towed at the vertical position of the riser base. The connection of the riser tower to the riser base is performed by ballasting the sub-surface buoy, and by pulling down the riser tower by means of subsea winches. Once the tieback connector is landed on the riser base and confirmed by ROV, the connector is hydraulically locked. When connection operation is achieved, the Sub-surface Buoy is de-ballasted to reach the nominal tension, the tower is ready for top connection to the floater and bottom connection to sealines with respectively flexible risers and flexible jumpers. A typical top connection mainly consists in: -

Perform first end flexible riser initiation on top of the riser tower

-

Once the connection is completed, the flexible riser is laid in the direction of the FPSO A messenger line followed by the pull-in cable is transferred from the floater to the installation vessel Connect the pull-in cable to the pull in head and start lowering the flexible riser using the A&R cable

-

When the load transfer is achieved, disconnect the A&R cable by ROV and pull the flexible riser in I or J tube

-

Lock the flexible riser bend stiffener in the I or J tube and secured the flexible riser to the hang off platform.

Please refer to document "Tie-in methods" (Reference 6) for bottom connection using flexible jumpers.


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9.3.4


Drilling riser running techniques applied to top tensioned risers

The main technique used for the installation of top tensioned risers is the conventional drilling riser running techniques as used for the TLP (see figure 23) The following will describe two different riser installations, but also based on drilling riser technique: (1) top tensioned riser tower deployment from a semi-submersible (Enserch Copper Project, Garden Bank 388) and a SPAR (Oryx Neptune Project). I.

Installation of top tensioned riser tower from semi-submersible (see figure 21)

a) Recover the protective cover over the riser base with the drill pipe running tool b) The assembly composed of lower riser connector and stress joint is brought up through the V door and lowered down through the spider setting the upper end of the stress joint on the spider c) Bring the first riser joint up into the derrick, land it on the upper stress joint flange and perform bolt flange connection d) Perform regular riser joint (e.g. 12m long) installation to reach the required riser length e) Install quarter sections of external air tank on the last 2 riser joints (or required length) by bolting them together around the riser joint as it run through the moonpool f) Bolt the upper riser connection mandrel to the top of the last riser joint to complete the assembly of rigid part of the riser g) Install the riser installation string on the upper riser connection mandrel then lower the riser to the riser base using the heave and motion compensator h) Once the lower riser connector is landed on the riser base and confirmed by ROV, the connector is hydraulically locked by ROV. i) Pump air in the two external air tanks through a temporary umbilical to make the riser neutrally buoyant j) Lower gas export line bottom termination through the running string by welding joints as needed, land and lock both ends from the inside using drill pipe running tool k) Using guide frame and assisted by diver or ROV, position casing and tubing into the proper location within the upper riser connection package l) Lower annulus and production lines having stab latches at the lower end that lock to riser base receptacles m) Pump air in the two external air tanks to make the riser positively buoyant and therefore self-supporting n) Position the upper riser connector package in the moonpool and connect the flexible lines to the gooseneck hubs at one end and pontoon porches at the other o) Using drill pipe, lower the upper riser connector package to the upper riser connector mandrel p) With the lift off cylinders, lower the mini-connectors onto the flowline hubs and hydraulically lock them in place. q) Lower and connect the upper riser sheave package to the upper riser connector package r) Activate the riser management system to maintain the riser within the desired watch circle Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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II.


Installation of top tensioned riser from Spar (see figures 22 & 24)

Note: Buoyancy cans and stems are installed when the deck module is installed. The lower two of each set of three cans are flooded and the cans are resting on their down stops. This placed the upper end of the buoyancy can's stem at the production deck level where the riser-landing ring with the load cells is attached.

a) Riser installation starts with the crane lifting the tieback connector/stress joint/lower transition joint and keel joint subassemblies aboard, upending and hanging each in a vacant well slot. b) The rig is skidded over the keel joint first, which is picked up through the rotary table and stored to one side. Then the rig is skidded over the tieback connector/stress joint/lower transition joint, which is also picked up through the rotary table c) Once the rig is skidded over the well slot and the messenger line, attached to the lower end of the tieback connector stab sub, the subassembly is landed in the spider d) Buoyant joints are lifted up through the V-door and made up to the threadedand-coupled connection at the upper end of the lower transition joint. Threadedand-coupled riser joints are added until the proper length is reached for keel joint placement. e) An upper transition joint, the keel joint, and second upper transition joint are placed in the string before running of standard joints continues. f) When total riser length is reached, the waveform joint is made up and the string slowly lowered as the ROV observes and laterally assists in stabbing the tieback connector into the wellhead. The ROV then locks the connector through an hydraulic hot stab. Afterwards, riser string over-pull and internal pressure tests are made to verify connection integrity. g) The riser is pulled to its operating tension while the Spar is de-ballasted to its proper draft. The adjustable riser support structure is extruded to its full up position, the waveform joint slips set, and the surface wellhead is attached to the landing ring. With the riser lowered slightly, the excess length of waveform joint is removed and the isolation seal and tubing spool are installed. Once the BOP spool and surface BOP are attached, the well is ready for downhole completion activities. h) After the downhole completion is installed and the production and gas lift tubing is landed and hung from a packer just below the seafloor wellhead, dual tubing strings along with a control/chemical injection umbilical are run through the riser and suspended from the surface wellhead. Finally the surface tree is landed and locked to the tubing spool and the jumper flowlines and umbilical connect the platform based manifolds and control equipment. i) When the well is on stream, the riser's weight is transferred to the buoyancy cans. This load transfer requires careful co-ordination of buoyancy can deballasting and Spar ballasting. Once the load transfer is complete, the adjustable riser support structure is removed and the riser system cans provide complete support and tensioning of the production riser system.


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10


10.1

General

Risers play an important part in the drilling, production, and transportation of hydrocarbons and other associated fluids with any offshore oil and gas production. For a floating production system, risers provide the link between the floating platform and: -

the oil/gas wells close to or underneath the floating platform,

-

subsea satellite wells at some distance from the platform,

-

other floating or fixed platforms,

-

export facilities, either a pipeline to the shore or to a shuttle tanker loading facility.

The risers may handle: -

Drilling or production.

-

Hydrocarbon imports (from remote wells/platforms),

-

Hydrocarbon exports (via pipelines to shore, another platform or a storage unit).

-

Water or gas injection (into the reservoir to increase pressure and force the oil up the well). - Gas lift (gas pumped into the bottom of the well or at the riser base to help the oil to flow more rapidly up to the floating production system). Note: Other risers such as hydraulic and electrical lines, work-over risers are not covered by this study.

Risers may be classified either as rigid or flexible: -

Rigid risers manufactured from steel pipe and generally found in free hanging configuration or in a vertical position (top-tensioned riser or hybrid riser tower).

-

Flexible risers manufactured from layers of wires and polymers, which are hung in suspended catenary or free hanging configuration.

10.2

Flexible risers

Flexible risers have the advantage that they can accommodate larger platform motions than rigid risers. They are suitable, even in high sea states, for use with semi-submersibles and turret moored ships when rigid risers would be unsuitable. Although flexible flowlines are more expensive than rigid steel pipes (due to sophisticated plastic materials and manufacturing methods) they are utilised for the development of short distance between wells to production facilities, and also the development of deepwater small and marginal fields. In these types of application, the used lines could be recovered from the sea bottom, transported to onshore base and submitted to inspection and refurbishment, to assure a safe and efficient reutilization. In predominant seabed irregularities where flexibility is required flexible pipes are also used. Despite the inherent advantages in the use of flexible risers, there are technical and economic limitations. It is well recognised by the industry that the use of flexible risers from the floater to the sea floor in deepwater needs exceptional flexible pipe design to withstand the extreme external hydrostatic pressure and large top tension. On top of this , flexible pipes of the sizes anticipated for export lines are at the current limits of manufacturing capabilities. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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10.3


Steel risers

The use of risers made of rigid pipe become more economical for deepwater applications as: -

the rigid pipe has no specific limitation concerning the water depth (the limits are mainly fixed by the laying capacity of the installation vessel, the deck space and load of floating production system)

-

the reduction of the difference between the installation cost of rigid riser and flexible lines in deepwater, combined with a lower fabrication cost for the rigid line, turn the rigid pipe riser into a cost effective alternative.

-

the flexibility of the overall riser in production phase increases with the water depth (i.e. increased riser length induces increased flexibility).

At present, the steel pipe is mainly used in three types of riser configuration: -

top-tensioned risers

-

steel catenary risers

-

offset hybrid riser tower

10.3.1 Top-tensioned riser tower The original philosophy for the top-tensioned riser tower, developed by Cameron Iron Works in early 1983 for Placid Oil, was to design a system, for small or marginal fields, that could drain a reservoir and then move on to a new location. By utilising established technologies and fabrication methods, the top-tensioned riser tower has been proven to be a viable and cost effective solution for deepwater projects. This technique is well adapted to marginal fields using subsea drilled and completed wells tied-back to a floating production system located directly above the subsea template/wells. When compared with the offset hybrid riser tower, the top-tensioned riser tower has the advantage of optimised jumper length, The coupled motions of the riser and the floater, by means of tensioned system or buoyancy cans, allow the installation of short jumpers, thus reducing the overall project cost. However, a relatively stable floating production system is required to avoid the disconnection when hurricane conditions are encountered: for a floating production system with a large number of risers it is not practical to disconnect and it is undesirable to lose position. Furthermore, the number of risers, tensioned using tensioner system with multiple wires, hydraulic accumulators and jacks, is limited on the semi-submersible due to space requirements and complexity of the tensioning system. In the more severe environments special platform designs will be required. These may be: -

Tension Leg Platforms, which are constrained to move approximately on the same arc as the top of the riser. The TLP riser tensioner is much simpler than the tensioner required on a semi-submersible owing to the very small stroke requirement (i.e. TLP low heave motions), so multiple risers are practical.

-

Spar platforms, where the risers are tensioned by internal buoyancy cans in a deep centre well in the platform


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10.3.2 Steel catenary risers Steel catenary risers offer advantages over risers made of flexible pipe since steel catenary risers are much less expensive. Steel catenary risers also offer advantages over top tensioned risers since steel catenary risers need no heave compensation, no subsea connections, and no flexible jumpers to transition to fixed piping at the production deck. For some applications a disadvantage of steel catenary risers compared to top-tensioned risers is the length of active footprint on the seafloor. If soft soil conditions are encountered, problems of pipe self-embedment at touch-down point may appear, thus limiting the compliance of this area and increasing stress magnitude. Another major problem with some steel catenary risers is the high bending stress where the riser touches down. Tension is typically low near touch-down point, so the riser is easily bent. In addition to a high static touch-down curvature, the situation is often exacerbated by severe dynamic response – characterised by waves travelling down the riser. Theoretically, the problem is a complicated one, involving local tension, drag, mass and weight distributions, as well as global dynamics. However, it is possible to overcome the problem by using a length of titanium pipe in the touch-down region. Consideration of the higher and lower stiffness of titanium shows that the minimum allowable radius of curvature of a titanium pipe is three to four times less than that of a steel pipe with the same outside diameter and wall thickness.

10.3.3 Offset hybrid riser tower The hybrid riser concept is not very sensitive to the water depth as increasing the length of the steel bundle and the wall thickness of the lower part are the main required operations to increase the range of use of an hybrid riser tower in terms of depth. The hybrid riser tower, as it is not rigidly linked with the FPS, can be used with a floater that has a relatively large dynamic response, such as an FPSO. The compliance of the riser bundle combined with the flexibility of the jumpers allows to withstand its motions. Moreover, the concept allows to decrease (with reference to a classic catenary configuration) the loads (vertical and horizontal) applied to the FPS as only the jumpers weight is supported by the floater. This becomes important as the water depth and the riser number increase. Another advantage of this riser concept is to avoid any fatigue problem on the main part of the riser: the steel bundle provides a relative stability along its length. The critical points are mainly the jumpers, their interface with the steel bundle, the subsea buoy, the flex-joint connection, and finally the lower part of the riser anchoring, which require accurate engineering studies. However, extensive engineering, qualification program and model test are being performed to gain confidence in its deepwater application (i.e. Girassol Deepwater Development).


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11



The advantages and disadvantages of several different configurations relevant to flexible and steel risers including hybrid risers are summarized in the following table 13:

Configuration

Advantages

Free hanging catenary - Simple configuration (for flexible and rigid - Very simple installation pipe)

- Simple pipeline connection at seabed

Disadvantages - Liable to rapid wear at seabed touch down point - Unsuitable for shallow water (rigid pipe) - High static load at top end connection - Wear at seabed can be exacerbated by fluctuations in oil density or slugging causing repeated lift-off and set-down - Resistance to dynamics associated with vessel heave - Cyclic fatigue due to vessel motion combined with current and hydrodynamic loads

Lazy S

- Simple pipeline connection - Mid-water support is relatively stable


- Potential wear at seabed if buoy tension is insufficient

- Good possibilities for multiple line applications

- Need to control bending at end terminations and at mid-water buoy

- High mid-water velocities may be counteracted by a large mid-water buoy with high tension and lateral stiffness

- Mid water buoy must be configured so that it does not move adversely in high mid-water velocities

- Lower seabed wear than a freehanging catenary

- Wear at seabed can be exacerbated by fluctuations in oil density or slugging causing repeated lift-off and set-down.

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Configuration

Steep S


Advantages - Wear at seabed eliminated - Good possibilities for multi-line applications

Disadvantages - More complex connection at seabed - Possible yaw instability of midwater buoy - Seabed unit must resist upward forces

Lazy Wave

- Less complex seabed connection - Mid-water support stable - Simple installation and pipeline connection

- Potential for rapid wear at seabed touchdown (greater than for lazy S but may be less than for free hanging catenary - Wear at seabed can be exacerbated by fluctuations in oil density or slugging causing repeated lift-off and set-down. - Susceptible to large motions in cross currents - Not well suited to slug flow in riser - Not well suited for closely spaced, multi-line applications due to possible interference

Steep wave

- Wear at seabed eliminated

- More complex connection at seabed

- Mid-water support stable - Possibility for multi-line application when used with spacer frames

- Susceptible to high transverse current velocities - Seabed unit must resist upward forces


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Configuration

Pliant wave


Advantages - Movement restricted and hence potential for wear at seabed reduced - Seabed approach may be specifically designed to resist wear

Disadvantages - Seabed unit must resist forces from riser - Restraint attachment to riser adds complexity

- Mid-water support stable - Restraint against movements due to current

Hybrid riser

- Combines advantages of rigid and - Overall complexity and cost may flexible risers to improve limit applications to deepwater performance under vessel motion systems and environmental loading - Potential of flow induced vibrations - Lower rigid section relatively particularly for multi-line stable and requiring minimum applications maintenance - May require more facilities for - Compliance assists connection to installation and work-over of upper a floating unit with a wide motion and lower units envelop (FPSO or semisubmersible) - Upper flexible lines individually retrievable - Upper flexible section isolates lower section from extreme dynamic effects at sea surface - Well adapted for riser system where flow assurance is critical - Well adapted for congested area - Reduced deck space and payload on floating unit - Top riser including sub-buoy is accessible by divers for installation and maintenance


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Configuration


Advantages

A - Top tensioned riser - Long lengths are achieved by tower assembling shorter, identical lengths (semi-submersible) - If one element is damaged or suffers wear, it can be changed out - Ease of intervention access for traditional drilling and well workover equipment - No requirement for installation vessel during all field life

B - Top tensioned riser (TLP)

Disadvantages - Top tensioning system limits number of risers particularly on semi-submersible - Complex and heavy subsea manifolding in case of multiple wells and import/export lines regrouped on the same riser - Difficult option in case disconnection is required in severe weather - Integral bundle riser has to be retrieved as a complete unit for servicing any riser in it

- Riser system constrained to move approximately on the same arc as the floating unit particularly for Spar and TLP

- Top tensioning system is simpler due to small stroke requirement

- Long lengths are achieved by assembling shorter, identical lengths

- Cannot be disconnected in severe weather

- Multiple risers are practical

- If one element is damaged or suffers wear, it can be changed out - Ease of access for traditional drilling and well work-over equipment - No requirement for installation vessel during all field life - Ease of maintenance in case tree located on platform - Any riser can be retrieved or installed without affecting the operation of the other risers


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Configuration

C - Top tensioned riser (Spar)


Advantages

Disadvantages

- Riser system constrained to move approximately on the same arc as the floating unit

- Top tensioning system replaced by buoyancy cans (passive)

- Long lengths are achieved by assembling shorter, identical lengths

- Cannot be disconnected in severe weather

- If one element is damaged or suffers wear, it can be changed out - Ease of access for traditional drilling and well work-over equipment - No requirement for installation vessel during all field life - Ease of maintenance in case tree located on platform - Any riser can be retrieved or installed without affecting the operation of the other risers Table 13: Advantages & Disadvantages of different riser configurations


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The advantages and disadvantages of riser tie-off at deck level and pontoon are also presented in table 14:

Configuration

Deck level tie-off

Advantages - Longer catenary therefore greater compliance - Access for installation, inspection and maintenance are simpler - No requirement for underwater connection

Disadvantages - Full wave forces and motions must be resisted through the splash zone - Difficulty in releasing coupling in severe weather when the floater is displaced from its central location - FPS stability and payload reduced

- Potential for easier FPS conversion

Pontoon tie-off

- Reduced wave loading on riser

- May require diving for riser installation and spool connection

- Better FPS stability - Access for inspection and maintenance activities is: not simple, limited to calm sea conditions and may require diving - Damage to attachment points may go unnoticed Table 14: Advantages & Disadvantages of top riser tie-off point


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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK UMBILICALS


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TABLE OF CONTENTS 1

2

INTRODUCTION ............................................................................................................ 4 1.1

SCOPE ....................................................................................................................... 4

1.2

REGULATIONS, CODES, STANDARDS & SPECIFICATIONS............................................... 5

1.3

DEFINITIONS & ABBREVIATIONS ................................................................................... 5

1.4 1.5

REFERENCES ............................................................................................................. 6 ACKNOWLEDGEMENTS ................................................................................................ 6

INTERFACE REQUIREMENT........................................................................................ 7 2.1

GENERAL ................................................................................................................... 7

2.2 FLOATING PRODUCTION SYSTEM ................................................................................. 7 2.2.1 I//J tube and pulling winch ............................................................................................ 7 2.2.2 I/J Tube seal ................................................................................................................. 8 2.2.3 Topside hang-off assembly .......................................................................................... 9

3

2.3 2.4

INTERMEDIATE CONNECTION ....................................................................................... 9 SUBSEA PRODUCTION SYSTEM .................................................................................. 10

2.5

CAPS ....................................................................................................................... 13

2.6

LAYING VESSEL AND EQUIPMENT ............................................................................... 13

UMBILICAL TECHNOLOGY & MANUFACTURERS REVIEW .................................... 16 3.1

GENERAL ................................................................................................................. 16

3.2

THERMOPLASTIC HOSE UMBILICAL ............................................................................. 21

3.3 3.4

STEEL TUBE UMBILICAL ............................................................................................. 23 POWER AND CONTROL UMBILICAL .............................................................................. 27

3.5

INTEGRATED SERVICE UMBILICAL ............................................................................... 29

3.6

SUBSEA TERMINATION INTERFACE ............................................................................. 33

3.7 3.8

SUBSEA BEND RESTRICTOR ....................................................................................... 35 TOPSIDE BEND STIFFENER ........................................................................................ 36

3.9

TOPSIDE TERMINATION SYSTEM ................................................................................. 37

3.10 EXTERNAL CORROSION PROTECTION ......................................................................... 37 4.

TEST REQUIREMENT ................................................................................................. 39 4.1

GENERAL ................................................................................................................. 39

4.2 4.3

MATERIAL QUALIFICATION TESTING ............................................................................ 39 UMBILICAL DESIGN QUALIFICATION TESTING ............................................................... 40

4.4

ACCEPTANCE TESTING .............................................................................................. 40

4.5

EXTENT OF FLUSHING, PRESSURE TESTING, CLEANING & PRESERVATION..................... 42


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5.


INSTALLATION TECHNIQUES ................................................................................... 43 5.1

GENERAL ................................................................................................................. 43

5.2 LAYING EQUIPMENT .................................................................................................. 45 5.3 LAYING METHODS AND PROCEDURES ......................................................................... 46 5.3.1. General ....................................................................................................................... 46 5.3.2. Installation procedures ............................................................................................... 47 6.

APPLICATIONS & LIMITATIONS................................................................................ 53 6.1

THERMOPLASTIC HOSE UMBILICAL ............................................................................. 53

6.2 STEEL TUBE UMBILICAL ............................................................................................. 58 6.2.1. Carbon steel: .............................................................................................................. 60 6.2.2. Duplex and Super Duplex Stainless Steel ................................................................. 61 6.2.3. Titanium alloy ............................................................................................................. 61 6.2.4. Summary .................................................................................................................... 61 7.

ADVANTAGES & DISADVANTAGES ......................................................................... 62 7.1

THERMOPLASTIC UMBILICALS .................................................................................... 62

7.2

STEEL TUBE UMBILICAL ............................................................................................. 62

7.3

INTEGRATED SERVICE UMBILICAL .............................................................................. 63

ANNEX 1 : MANUFACTURER ADDRESS.......................................................................... 64


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1


INTRODUCTION

1.1

Scope

The current trend among oil companies is a move towards extensive use of subsea production systems to develop new deepwater fields. These production systems are typically remotely operated from an adjacent manned installation via umbilicals which provide the following functions: -

Hydraulic power for the operation of actuators

-

Electrical power for the power supply of control pods, electrical pumps, etc.

-

Electrical signal for the operation of control valves

-

Data transmission for the subsea manifold and well monitoring

-

Fluid transmission for well services (e.g. methanol, corrosion inhibitor, etc.)

Umbilicals are structures that contain two or more functional elements, i.e. thermoplastic hoses and/or metal tubes, electrical cables and optical fibres. These are typically assembled together with a helical technique, to form a circular bundle, which is then encased in an extruded thermoplastic sheath, reinforced with two contra-helically applied layers of steel wires and finished with a second extruded thermoplastic sheath. Many offshore projects require the consideration of greater depths, longer umbilicals and more control functions than those common in the past. Further, most oil companies are striving to reduce the time required to complete such developments, i.e. fast track projects. As a result, the selection of umbilicals has become more critical as many factors such as performance, fluid compatibility, impact on interfaces, ease of deployment, etc. must be considered during the selection process. This document aims at providing valuable information to help the design engineer in the selection of the most suitable umbilical, knowing that a detailed analysis during the engineering phase is essential to ensure that all of a specific project’s unique features and needs are fully addressed. Since umbilical performance is a function of material, size, length and other parameters, chapters 2 and 3 give an overview of available umbilical technology and the associated topside and subsea interface requirements. As electro-hydraulic control systems are widely used in deepwater applications and require a high level of umbilical reliability and tube cleanliness, the test requirements from the reception of core components in the manufacturing facility to the umbilical installation in the field are presented in chapter 4. Chapter 5 is dedicated to the description of some typical umbilical configurations found in deep waters including installation methods / sequences and laying equipment. Virtually all production control system applications are based on the use of either thermoplastic hose or metal tube. The limitations of these fluid lines are described in chapter 6. The presentation of advantages and disadvantages of different types of umbilical in chapter7 will conclude this document.


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1.2


Regulations, Codes, Standards & Specifications

Specification for subsea production umbilicals

API 17 E

Subsea umbilicals

ISO 13628-5

(This standard is in draft form only and will ultimately replace API 17 E)

National Aerospace Standard

NAS 1638

Hydraulic oil cleanliness requirements Galvanised steel wire for armouring cables

BS 1441

International Electrotechnical Commission

IEC 228

Conductors of insulated cables Extruded solid dielectric insulated power cables for rated

IEC 502

voltage from 1kV up to 30 kV Rules for submarine pipeline systems

DNV 81 (Amended as needed by DNV 96)

British standard code of practice - pipelines

BS 8010

Standard specification for seamless and welded

ASTM A789/789M-90

ferritic/austenitic stainless steel tubing for general service Chemical plant and petroleum refinery piping

ANSI/ASME B13.3

Standard specification for polymer properties

ASTM (see section 6.1, table 03)

The determination of particulate contamination in liquid by the

ARP (SAE) 598A

particle count method Remark: Mechanical Engineering Centre of European Gas Turbines Ltd. (previously ERC committee) is working on the generation of an API steel tube umbilical specification. Current steel tube wall thickness determination is based on manufacturer rulings.

1.3


BOP

=

Blow-Out Preventer

FAT

=

Factory Acceptance Test (of umbilical)

FPS

=

Floating Production System

HDPe

=

High Density Polyethylene

ISU

=

Integrated Service Umbilical

LDPe

=

Low Density Polyethylene

ROV

=

Remote Operated Vehicle

SAE

=

Society of Automotive Engineers

SCC

=

Sulphide Cracking Corrosion

XLPe

=

Cross linked polyethylene


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1.4


References 1.


2.

In-house technical database

3.

In-house experience in selection and installation of thermoplastic, steel and integrated service umbilicals

4.

Manufacturer and subsea contractor product leaflets

5.

Deepwater Field Development - Reference Book – “Tie-in Methods”

6.

Document n° TOTAL/Z/EN-004/98 (SEAL Engineering) Deepwater Field Development - Reference Book – “Sealines” Document n° TOTAL/Z/EN-005/98 (SEAL Engineering)

1.5

7.

Deepwater Field Development - Reference Book – “Riser Systems”

8.

Document n° TOTAL/Z/EN-006/98 (SEAL Engineering) TOTAL General Specification SP - ELC - 143, Subsea Cables

Acknowledgements



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2



2.1

General

The main interface requirements in the umbilical design are related to: -

Floating production system (or ‘host’ platform)

-

Intermediate connection between static and dynamic umbilical

-


-

Installation equipment & vessel

The above requirements are described in the following sections.

2.2


Typical standard equipment on the floating production system includes:

2.2.1

-

I/J tube and pull-in winch

-

Topside hang-off assembly and connection

-

I/J seal

-

Topside bend stiffener

I//J tube and pulling winch

Flexible or steel umbilicals comprising power, signal and fluid lines are frequently brought into topsides through steel I/J tubes pre-installed on the pontoon or deck level of the floating production system. This is performed using a winch located above the J-tube, which draws a cable attached to the nose/pulling head of the umbilical (see figure 01). The I/J tubes are designed to protect the umbilical against environmental loads (wave and current), fires and accidental collisions with vessel. They are often equipped with a bellmouth system using mechanical dogs to hold the umbilical bending limiter with a conical structure (see figures 02 and 03).


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Hydraulic power unit

Cable storage winch

Linear pull-in winch

Pull-in cable

Floater structure

Figure 01 – Pull-in winch general arrangement

2.2.2

I/J Tube seal

The I/J tube seal centralises the umbilical at the I/J tube entry and provides a seal against sea water, preventing dilution of corrosion inhibitors (see figure 02). The seal can be preinstalled on the umbilical or diver installed during installation.

Umbilical

Seal plug

I/J tube

Bellmouth

Figure 02 – Seal plug The I/J tube seal can either be delivered as a moulded or packer-type sealing element.


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2.2.3


Topside hang-off assembly

The topside hang-off assembly provides a structural element to transfer the pull-in loads from the umbilical during installation, and into the platform J-tube after the installation is completed (see figure 03). Topside umbilical interface

Surface Termination : Armor Pot With Hang-Off Split Plate

Pull-in head

Surface Termination During Installation ; Including : Pull-In Head, Armor Pot, "J" Tube Collar And Bend Stiffener

Bend stiffener "J" Tube On Floater

Umbilical

Bend stiffener

Pull-out Clamp (contingency) Umbilical

Figure 03 – Topside hang-off arrangement

2.3

Intermediate connection

The umbilical riser splice is the connection unit between the dynamic and static part of the umbilical. The unit comprises suspension points, and connects the tubes with threaded type fitting or welded splices for both steel tubes and electrical cables. The riser splice also has oil-filled, pressure-compensated chambers containing electrical penetrators (see figure 04). This device is mainly used when the static and dynamic cross sections of the umbilical are different or when the umbilical is too long to be fabricated in one-piece length. The intermediate connection is mainly performed offshore, onboard the laying vessel. Non armoured umbilical cable

Tube separators Armoured umbilical cable (dynamic umbilical)

Weld type or compression fittings

bend stiffener

Anode protectors positioned between tie bars Static umbilical

El

ti

bl

Final assembly filled with 'WIRELOCK RESIN' li

Figure 04 – Typical arrangement of joint box for a steel tube umbilical Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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2.4



Deepwater subsea umbilical termination system is either a termination head (see figure 05) or termination unit (see figure 07) depending on the type of umbilical (hydraulic umbilical, electrical umbilical, electro-hydraulic umbilical, integrated service umbilical etc.) and selected tie-in method. The complete subsea termination system comprises the following elements: - Subsea termination interface - Bend restrictor/ bend stiffener hang off (bend limiter is also possible) - Tubing support, including check valves, flanges, etc. - Electrical penetrators and connectors The electrical penetrators and connectors are placed inside an oil-filled, pressurecompensated chamber. With respect to the electrical cables, the philosophy of using a minimum of two barriers against water ingress is maintained throughout the entire system. c Service line VIEW SHOWING ONLY HYDRAULIC ELEMENTS Fluid lines

Hydraulic tubes

c

Section cc

VIEW SHOWING ONLY ELECTRICAL ELEMENTS Penetrators

Electrical connections Marine electrical connectors

ROV grab bar

Orientation key

FULL VIEW Hub (tie-in) ISU end termination interface Carrier pipe / orientation sleeve

Figure 05 – ISU termination head general arrangement The subsea termination system is typically manufactured in mild steel, painted and cathodically protected. The design of the subsea termination system is related to the selection of one of the three following connection methods from the subsea end of the umbilical to the subsea structures: -

Clamp or collet connection: The installation of the umbilical can be based on either a stab and hinge-over method or direct pull-in method. The chosen connection method will have an impact on the design of subsea structure and connection system. For further information on subsea structure interface requirements, please refer to document "Tie-in Methods" [reference 05] of Deepwater Field Development – Reference Book. This type of connection


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method is mainly used for the hydraulic umbilical with a high number of lines or high stiffness of the individual lines, which make the use of jumpers difficult (e.g. Integrated Service Umbilical) (see figure 06).

Seal plate Marine electrical connectors Tie-in hub with hydraulic couplers

Carrier pipe with orientation sleeve

Clamp connector (pull-in and protection)

(for each termination head)

Subsea termination

Figure 06 – Connection system using subsea termination head and clamp assembly to connect integrated service umbilical to subsea structure -

ROV-installed junction plates: The ROV-operated junction plate assembly consists of independent junction plates attached to mechanical arms which pivot on joints that are fixed to subsea structures or mounted on retrievable subsea control pods. Female coupler junction plates are generally mounted on the subsea structures such as tree, control pod, umbilical termination system, etc. Flexible jumpers allowing the subsea connections from subsea umbilical termination system are fitted at both ends with male coupler junction plates (see figure 07). The subsea connection is performed using ROV and its dedicated tooling package in ‘free-flying mode’. It is therefore applicable only for electrical and/or hydraulic ‘flying leads’. This technique (i.e. ‘free-flying mode’) is not applicable to the Integrated Service Umbilical due to its central service line stiffness and termination head weight.


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Umbilical Termination Unit

Junction plate

Junction plate affixed to subsea tree

Umbilical with bend stiffener

Flying lead terminated with junction plate X-mas tree Hydraulic coupler Electrical connector ROV operated juction plate

Figure 07 – Connection system using subsea umbilical termination unit and ROV operated junction plates -

Subsea flying lead : Electrohydraulic connections between subsea installations can be accomplished with an ROV-installed flying leads (see figure 08). A flying lead is deployed subsea using a compact frame. The ROV pulls one end of the flying lead from the frame and swims to the receptacle mounted on the subsea structure. Then the ROV returns to the deployment frame and pulls the other end of the flying lead and swims and connects it to the subsea umbilical termination unit or subsea termination assembly. This connection method is well suited for umbilicals with a limited number of small hydraulic lines or electrical cables.


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ROV handle

Receptacle

Connector

Figure 08 – Wet mateable connection principle applied to electrical cable

2.5

Caps

The umbilical is provided with protection caps and preservation caps installed on the subsea termination system. The purpose of the protection cap is to provide mechanical protection and prevent contamination of the connectors and seals faces. The purpose of the preservation cap is, in addition to mechanical protection, to enable pressurisation of the fluid lines above the ambient in hydrostatic pressure in order to compensate for pressure variations in the lines during laying operations and prevent ingress of dirt and moisture.

2.6

Laying vessel and equipment

The equipment required for the umbilical laying from an installation vessel (see figures 09 and 10) is listed below: -

Horizontal powered reel, vertical powered reel or carousel for the storage of umbilical (Integrated service umbilical and steel tube umbilical will be mainly stored in horizontal powered reel).

-

Straightener / spooler to assist in loading and unloading the umbilical. The straightening function is only required for the laying of integrated service umbilical/steel tube umbilical,

-

Tensioner / aligner to align the umbilical with the tensioner central axis and retain the laying load tension, Overboard chute to control the umbilical curvature,

-

A & R winch to abandon umbilical on seabed and recover it in case of problem.


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Horizontal powered reel

Overboarding chute

Figure 09 – Umbilical laying vessel – Seaway Condor


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Umbilical stored on horizontal reel

Termination head

Overboard chute

Umbilical termination head Bend restrictor

Straightener/spooler

Umbilical

Dual two tensioners

track

Figure 10 – Umbilical laying equipment for ISU


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3


UMBILICAL TECHNOLOGY & MANUFACTURERS REVIEW

3.1

General

Umbilicals are a combination of thermoplastic hoses, electrical cables, fibre optics and/or steel tubes which are assembled together to form a circular cross section. In order to provide axial tensile strength and abrasion resistance, the product can be supplied armoured with steel wires prior to extruding an outer thermoplastic sheath or applying a roving layer. Different types of umbilical are shown in figure 11.

Figure 11 – Sample of different umbilical types The hydraulic lines can be employed for a variety of duties, typically: •

Power (operation of actuators)

•

Signal (operation of pilot control valves)

•

Data (pressure monitoring)

•

Fluid transmission and chemical injection (well service and platform utilities)

Hydraulic lines may be either reinforced thermoplastic tubing or steel tubing. The former can be in very long continuous and seamless lengths, whereas the latter are produced from shorter lengths, which are butt-welded to achieve the final production length. The shorter lengths may additionally be seam welded as part of the steel tube production process. NDT and heat treatment shall be carefully supervised as possible source of failure.


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The electrical lines are divided into two categories: •

Power cables for the power supply of offshore platforms and subsea production equipment (control pod, repeater, pilot control valve, electric pumps, etc.)

•

Signal cables for the remote control/monitoring of subsea production equipment (operation of pilot control valve, readback of wellhead status and operating parameters, etc.) from host facilities (fixed platform or floating production system)

The arrangement of hydraulic lines and electrical cables in a typical umbilical is shown in the following figure 12:

(PolyPropylene)

Figure 12 – Typical structure of electro-hydraulic umbilical The increasing use of subsea production systems for the exploitation of oil and gas has resulted in increased complexity of such systems. Additionally, as the confidence has developed in the use of subsea systems there have been considerable increases in the offset distance from the ‘Host’ platform. This has resulted in a very significant increase in the quantity of hydraulic lines being employed in many subsea developments and it is not uncommon to find a single development employing over 300 km of hydraulic lines. Coupled with the ever-increasing number and complexity of control and well service fluids it is important that compatibility between the hydraulic lines and these chemical fluids (i.e. material selection) is carefully addressed if service problems are to be avoided. The same considerations need to be given to all materials of construction used to contain service fluids within the overall system, e.g. seals, rigid pipe assemblies, etc.

Rev. 0

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The manufacturing techniques used in the production of umbilicals are similar to those used for flexible pipes; essentially helical lay-up, extrusion and armouring as shown in figures 13 to 17:

Figure 13 – Helical lay-up machine for steel tube umbilical

Figure 14 – Extruding machine


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Armour wires

Umbilical

Figure 15 – Armouring machine

Umbilical

Steel tubes (on reels)

Electric cables (on reels)

Umbilical

Figure 16 – Helical lay-up machine for Integrated Service Umbilical Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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However, several manufacturing processes are unique to the production of umbilicals: •

Thermoplastic hose braiding reinforcement: In order to reinforce a thermoplastic hose liner to provide a specific working pressure, large capacity high-speed braiders are necessary to apply high strength Aramid fibre (see figure 17). Unit lengths varying from a few metres to more than 20km can be manufactured without joint

Figure 17 – Hose braiding machine •

Umbilical assembly line: The functional components can be assembled using the reverse helix technique (i.e. clockwise and anti-clockwise alternated layers, method known as SZ) which provides the umbilical with the required flexibility. The SZ assembling machine is also used for the manufacture of integrated service umbilical and gas lift umbilical.

The main manufacturers of umbilicals are : 1.

DUCO (Dunlop Coflexip Umbilicals Ltd.)

2.

ALCATEL

3.

NORSK CABLE (ABB)

4.

KVAERNER

5.

MULTIFLEX (OCEANEERING)

6.

NKT

7.

PIRELLI

8.

JDR CABLE SYSTEMS

Full details (address) are provided in enclosed Annex 1.


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The design of an umbilical mainly features: •

Fulfilment of all the required functions

•

Material selection based on (1) fulfilment of their function, (2) compatibility with the other materials and fluids to be transported

•

Internal and external pressure, installation, thermal and dynamic loads shall be taken into account

•

Fatigue life must correspond to the required operating life

•

Internal and external corrosion must be addressed

•

Stability on seabed

•

Optimisation of the section to achieve the best dynamic behaviour, and eventually to obtain similar dynamic characteristics to adjacent risers (if possible)

The following sections present the technology and manufacturing process used in the production of different types of umbilical implemented in deepwater applications i.e. thermoplastic hose umbilicals, steel tube umbilicals, power & control umbilical and integrated service umbilical.

3.2

Thermoplastic hose umbilical

The construction of a typical thermoplastic hose comprises a seamless thermoplastic extruded liner, reinforced by one or more layers of braided high strength textile yarn, and an outer thermoplastic extruded sheath for mechanical protection (see figure 18). The liner (sometimes referred to as core tube) acts as a seal between the fluid and the external layers and is the means of containing the transmitted fluids. To achieve the design life for the umbilical system, it is imperative that a high level of compatibility exists between the liner and the contained fluids. Internal Thermoplastic Liner

1 Or 2 Fibre Braid Layers External Thermoplastic Sheath

Figure 18 – Typical flexible hose structure Thermoplastic hose liners are produced using an extrusion process. Polymer, in granular form, is melted and forced through a pin and die arrangement to produce a tube, initially greater in diameter than the finished product. Whilst still molten, the tube is drawn through a sizing die to reduce it to the required size, immediately followed by rapid cooling to solidify the product, to facilitate passage through the hauler and spooling onto the storage reel. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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In the extrusion process, forcing material through the breaker plate and die arrangement, can result in the liner tube exhibiting anisotropic properties (e.g. out of roundness hose). To allow the hose liner to transmit fluid at high pressures, the liner tube is reinforced with braided textile yarn. When pressurised, the hose liner is forced against the braided material resulting in some material flow into the interstices of the braided arrangement. This can result in varying stress levels around the circumference and along the length of the liner. Some thermoplastic hose umbilicals are shown in figures 19 and 20. Filler Electrical cable

Thermoplastic hoses

First armour layers

Second armour layers Polyethylene outer sheath

Figure 19 – Dynamic electro-hydraulic

Figure 20 – Static hydraulic thermoplastic umbilical

thermoplastic umbilical

The fibre braids typically of high strength Aramid fibre provide the mechanical strength to resist the hoses internal pressure. Standard end couplings can be attached to the hose in the normal manner, i.e. by one of several swaging techniques. In the early days of subsea production, Polyamide 11 was the commonly employed material construction for the hose liner and there were relatively few fluids to be conveyed. These were typically water based controlled fluids and methanol. With the introduction of electrohydraulic control systems demanding high levels of system cleanliness and thus ultra clean hydraulic lines, an alternative, Thermoplastic Polyester (with lower permeation rate), was employed to satisfy this aspect. The hoses used have to transport many different chemical fluids and also transmit hydraulic power. The problem with chemical fluids (e.g. methanol, glycol) used for hydrate formation prevention, is that it permeates through the current industry standard hose lining materials. This permeated fluid, which is retained by the umbilical inner or outer thermoplastic sheath, due to the thicker section and different material used, builds up within the umbilical structure and egresses from the umbilical at its ends. With fluids, such as methanol, disposal of significant quantities can present problems (environmental, cost).


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The introduction of XLPe (cross linked polyethylene) hose lining material has greatly reduced permeation rate, almost zero at seabed temperature, and is also resistant to a wide range of commonly used injection and hydraulic fluids. XLPe proprietary lining material was developed using a specific grade of HDPe, which is cross-linked using an original and patented (Duco), cross linking process. The action of cross-linking HDPe slightly improves its mechanical characteristics, but moreover it drastically improves its blistering resistance and its chemical resistance to liquid or gaseous hydrocarbons.

3.3

Steel tube umbilical

Umbilicals in general are vital parts of the underwater production technology. But their reliability has been questioned, as many problems have occurred during laying and operation. Therefore improvements have to be performed in order to increase the reliability of the product. It is also relevant to compare the umbilical reliability with the subsea communication cable reliability. The latter product group has a remarkable good track record, and "mature" umbilical designs should be expected to have the same kind of reliability. One of the problem areas was that the inner liner of the thermoplastic hoses showed compatibility problems with some hydraulic fluids and with methanol in particular. To comply with these compatibility problems the metal tube umbilical was introduced in the early 90’s, first for static applications then for dynamic applications (see figures 21 and 22). Metallic umbilicals, in which the traditional kevlar reinforced thermoplastic hoses were replaced by steel tubes, has several advantages over the traditional thermoplastic hose umbilicals with respect to permeation, fluid compatibility, hydraulic and mechanical properties (e.g. collapse resistant). Metal tubes offer potential technical, cost and reliability advantages, especially in deep waters. Metal tubes can be in carbon steel, zinc coated carbon steel (coiled tubing), duplex or super duplex stainless steel, titanium grade 12 or composite material. Since carbon steel tubes can be formed in continuous lengths, steel tube umbilical would not require girth welds. Using steel in dynamic applications opens up challenges, which must be overcome. The major challenge with respect to dynamic steel tube umbilicals is fatigue, and details of the general arrangement and configuration of the related products can be decisive on whether the required life is met or not. Super duplex steel tube has up to now been the steel material used in dynamic umbilicals due to high corrosion resistance. New type of coiled tubing made of zinc coated carbon steel has entered the market. This material has already been used in a number of static umbilical projects. A testing program carried out for Deepstar phase 3 showed that the fatigue properties of zinc coated carbon steel tube make it suitable also for use in dynamic umbilicals.


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In selecting the design parameters for a metal tube umbilical, the following topics must be considered: •

a simple cross section formed solely of helically wound metal tubes is a viable and potentially economical design (versus thermoplastic hose)

•

if included, the electrical conductors require protection from crushing loads and allowing the electrical conductors to move axially may improve the fatigue life and reduce likelihood of damage during installation. This is performed by means of PVC sheath.

•

proper selection of materials plays an important role in determining the lowest cost solution. Fluid compatibility and corrosion protection will also influence the selection

•

design details, such as splices, spooling, terminations and installation procedures, are important in successfully placing an umbilical into service without defects or damages

•

armouring and other layers that are candidates for incorporation in the umbilical cross section should each be considered carefully on their merits, that is, whether they actually increase reliability or serve a vital function.

The requirements for well service and length of the umbilical usually determine the number and internal diameters of tubes, and if included the size and number of electrical conductors. In making choices about the umbilical configuration, the designer must be aware and take into account all the facets of the umbilical application. This includes manufacturing process and equipment available for manufacture, installation method and procedure, static and dynamic loading, mechanical handling, storage, stability on seafloor, termination at the well and platform, cathodic protection testing, internal cleanliness, and repair. All of these aspects may be important in the installation and successful operation of an umbilical. Typical manufacturing process of metallic umbilical is as follows : 1. Seamless tube joints (in approximately 20m lengths) are welded together and put on small reels to bring the length up to required length. Butt welds in the tubes are carried out using orbital welding techniques (Gas Tungsten Arc Welding system) on a dedicated welding line, and are then passed through a real time radiography unit for validation. Radiographic results are stored electronically, initially on video tape and are then digitally stored on compact disc; this system enables rapid retrieval if historical examination should be required, 2. These reels are then loaded directly onto a vertical lay-up machine, and the tubes are helically bundled, tape-wrapped, and placed temporarily on a turntable storage carousel with diameters of 22 to 26 meters and weight capacity of about 600 Te approximately. 3. From this carousel, the umbilical is passed through an armoured machine or a polyethylene / polyurethane extrusion machine (or both) for armouring and sheathing. The completed umbilical is then taken up and stored by reel or carousel ready for termination head installation, factory acceptance test and dispatch.


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Steel tubes


Binding tape

Polyethylene

Electrical

sheathed

cables

tubes Armour layers

Figure 21 – Typical hydraulic steel tube umbilical (for both static and dynamic applications)


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Figure 22 – Dynamic electro-hydraulic steel tube umbilical

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Conventional steel tube umbilical is composed of a static umbilical laid on the seabed and a dynamic umbilical suspended to the fixed or floating production system. Some samples are shown in the following figure 23: Electrical cables

Steel tubes

Binding tape

Polyethylene inner sheath

Armour layers

Polyethylene outer sheath

Figure 23 – Dynamic electro- hydraulic steel tube umbilical

Electrical cable Steel tubes

Binding tape

Filler


Figure 24 – Static electro- hydraulic steel tube umbilical


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3.4


Power and control umbilical

The supply of electrical power from shore to platforms, between platforms or from platform to subsea installations is performed by means of submarine power cables (see figure 25). Supplying power to offshore installations from energy sources onshore makes for smaller and lighter offshore structures, lower manning requirements, and lower CO2 emission levels. With this solution any number of installations can be linked and provided with power from a common onshore power source. The power supply cable system can be expanded to form a network between offshore fields, providing flexible and safe power utilisation for the oil and gas industry. Two types of submarine power cables are to be distinguished “dry” design or “wet” design, the former being more reliable but at higher cost. The remote control of unmanned installations is another application for submarine composite cables. Most subsea power cables installed offshore have a fibre-optic element containing 832 optical fibres for signal transmission. The advantages of combining signal and power capabilities in one cable are: •

communication will not be influenced by weather or surface traffic

•

greater bandwidth compared to radio frequencies

•

higher data transmission rate with optical fibres

Power cable

Fiber optic cable

Outer sheath

Armour layers

Filler

Figure 25 – Typical power supply umbilical including fibre optic cores for control system Advanced umbilicals for the transmission of power, signals and fluids have been produced for the management and control of subsea wells. Electrical power and signal cables are designed and manufactured to suit the final bundle make-up, each component being sized to ensure a balanced and circular construction. Insulation and sheath materials are carefully selected to meet the requirements of the application (for subsea applications, polyethylene and polyurethane are the standard choices). Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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Electrical conductors comprise multi-strand copper, either tinned or plain. Strand size is determined according to specification (see section 1.2) and/or duty. Multi-strand construction ensures good flexibility for dynamic duties. Insulation materials are usually thermoplastic compounds, including polyethylene, crosslinked polyethylene, polypropylene and PVC. Data and signal transmission line options include twisted pair, triads or quads (screened if required) and coaxes of various specifications, all optimised for particular attenuation, capacitance, cross-talk, resistance and other required electrical parameters. To avoid electro-magnetic interferences, power cables are screened using either copper braid or aluminium/polyester film. Components are screened individually or in appropriate groupings, taking account of heat build-up and storage/handling requirement (i.e. Minimumbending radius). Fibre optic cables, where required are selected from standard basic units and then further processed as necessary (no limitation considering total length). Fibre optic is being used more widely for data transmission because of their large bandwidth capability and without interference problems. Multi- and single-mode fibres are available in a variety of buffering systems. Loose buffered systems utilise fibres in plastic or steel tubes, while tight buffered systems typically include a steel armour or Aramid reinforcement (see figure 26). The process of power cable or service umbilical manufacturing is as follows: •

Lay up: To achieve the best dynamic performance and to prevent stress build-up in the components during bending, all components are helically laid-up in a full 360 degree cabled construction. This promotes flexibility and helps to prevent transmission of stress to the component during dynamic applications

•

Armouring: Lightweight wire, or heavy duty contrahelical wire armour, can be provided for umbilicals, where required. Such armouring gives damage-protection from ship's anchors or from rock dumping or provides high tensile strength dependent on design. Armoured cables are torque balanced and can have either a single or double wire armouring to ensure maximum strength and protection according to application

•

Strength members: Aramid fibre braided strength members may be applied to provide high tensile strength, flexibility and low weight. Alternatively, central wire rope strength members can be used, if required

•

Sheathing: Extruded sheathing of most thermoplastic materials (polyurethane, polyethylene, nylon 11, polyester elastomer, polypropylene impregnated with bitumen are commonly used) is available for maximum mechanical protection and service life. Materials are selected for their resistance to a seawater environment, durability under handling and cost.


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Power cables Fibre optic cables

Polyethylene outer sheath Armour layers

Figure 26 – Dynamic power and control umbilical 3.5

Integrated service umbilical

The typical integrated service umbilical is a combination of one or more of the hereunderlisted elements: •

Service lines

•

Hydraulic lines

•

Chemical lines

•

Fibre-optic cores for data transmission

•

Electrical cables for power supply

•

Electrical cables for signal transmission

•

Production line

The cross-section structure of the umbilical is designed to handle the various characteristics of the individual elements. The concept offers full control of mechanical stresses and strains, combined with maximum flexibility. All elements in the cross-section are bundled together in a continuous helix. The outer sheathing is of extruded polyethylene or polyurethane. It offers the following main features: •

Resistance to aggressive fluids

•

Suitability for small and large diameter tubes

•

Subject to extremely high pressure over long distances

•

Continuous umbilicals for long offsets

•

Combination of service/production lines within the same umbilical

•

Increased lifetime of the umbilicals (due to high tensile strength and stiffness of steel tubes)

•

Steel tubes eliminates the need for additional armouring (e.g. dynamic application)


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The market of integrated service umbilicals is dominated by four major manufacturers: DUCO, KVAERNER, ALCATEL AND MULTIFLEX. Only Kvaerner integrated service umbilical technology differs from general umbilical design philosophies. The Kvaerner umbilical technology is based on design principles of subsea bundle technology. In the Kvaerner integrated service umbilical, hydraulic lines are combined with electrical cables and/ or fibre optic cables in a composite cross-section, the elements are separated by unique PVC profiles. These conduit profiles ensure that the cables and steel tubes are free to move relative to other elements and not be exposed to lateral loads as elements are not adjacent (see figure 28). In conventional ISU umbilicals, the elements are kept together by rubber or plastic material which lock the elements in their position in the cross section (see figure 27).

Service line

Electrical cables

Fiber braid filler

Steel tubes


Figure 27 – Conventional integrated service umbilical

Outer sheath

Electrical cable

Chemical injection Or hydraulic lines Service line

PVC profiles

Figure 28 – Kvaerner integrated service umbilical


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The lay length of the Kvaerner ISU is relatively long compared to conventional umbilical technology. The Kvaerner ISU is torque balanced as the manufacturing process ensures a controlled back twist of the hydraulic tubes. Umbilical loops during installation have never been experienced for any Kvaerner umbilical (e.g. Norsk Hydro TROLL, NJORD, VISUND). The Kvaerner umbilical concept allows individual design to suit a range of applications capable of transferring hydraulic fluids, electrical signals, power and fibre-optic signals. Service lines (typically 1,5" – 4") can easily be included and are placed in the centre, with the electrical signal and power cables, fibre optic cores and hydraulic tubing placed circumferentially around inside PVC conduit elements. The circumferentially placed members follow a helix trajectory. Each element is designed to sustain hydrostatic pressure. The axial strength in the Kvaerner umbilical design is provided mainly by the central metal tubing. Separate armouring layers to take axial loads and stresses are therefore not necessary. Where a thermoplastic or steel tube umbilical always has the electrical cables in the centre (see figures 29 and 30), the cable position within the Kvaerner umbilical is not critical. Covered by the PVC profiles, the electrical and fibre optic cables will bend around their own centre axis and not around the centre of the cross section (see figure 31). The electric cables in the Kvaerner umbilical are not subject to excessive strains. In addition, the conduit elements give protection against external loads. Electric and fibre optic elements can thus be placed in any position within the Kvaerner integrated service umbilical.

Electrical cable

Figure 29 – Electrical cables position in a thermoplastic umbilical


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Electrical placed In the center line and surrounded by steel tubes

Steel tubes

Armour layers

Outer sheath

Figure 30 – Electrical cables position in a typical steel tube position

Steel tubes

Electrical cable placed in the outer layer

Service line PVC profiles

Figure 31 – Electrical cables position in a Kvaerner integrated service umbilical


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The manufacturing of integrated service umbilical is based on either an horizontal (Kvaerner technology) or vertical (Duco technology) axis machine capable to support fifteen bobbins, each of which is capable of holding fifteen metric tons of tubing or electric cable. These unique manufacturing capabilities allow the production of integrated service umbilical with up to six-inch service line in the center, with the control functions placed around the circumference. The steel tube umbilical is designed for virtually any service application. Operating conditions will determine if the tubing material will be carbon steel, zinc coated carbon steel (coiled tubing), 316L duplex or super duplex stainless steel or titanium grade 12. The manufacturing process of Integrated Service Umbilical is as follows: Seamless tubes in length up to 23m are butt welded and progressively spooled into reels. The length of any reeled tubing depends on the tube size. The tube string welding is run on line composed of programmable orbital TIG (Tungsten Inert Gas) welding stations, real time X-ray inspection and CD recording. The Non Destructive Examination (NDE) system of inspection provides a 100% traceability ensuring that individual tubes and welds throughout the production are identifiable to their location within the completed umbilical and mapped to achieve a complete manufacturing history traceable to the original material certification, Completed tube strings are hydrostatically pressure tested prior to release for the umbilical lay up, Tested tube strings are loaded into the umbilical lay up machine, Seamless central service line (from 1.5” up to 6” OD and in approximately 20m lengths) are welded together and stored on the carousel. Welding, NDE and pressure test are performed as for the above seamless tubes, The hydraulic/chemical tubing strings and electrical cables together with the PVC profilers are helically laid up around the central service line, The circular bundle is 100% tape wrapped then directed to a temporary storage carousel. During the lay up operation tube to tube weld joints and electrical splices are performed in order to produce the required length, The umbilical is then passed through an extrusion line for the application of the polyethylene outer sheath and routed to a large storage turntable, ready for factory acceptance test, loading and transportation to the offshore site.

3.6

Subsea termination interface

As part of the umbilical technology, there is a wide range of umbilical termination equipment. The subsea termination interface provides a standardised interface towards the subsea termination assembly. The steel or flexible lines are capped and terminated with end fitting, while the electrical cables are prepared for termination and water-blocked using heat shrink adhesive caps, prior to factory termination with electric cable subsea connectors (see figure 32). The subsea termination interface comprises the following main elements: -

Bend restrictor / bend stiffener radius control

-

Attachment to the umbilical and the subsea termination assembly (e.g. flanges, connectors)

-

Tubing support (e.g. tube separator, clamp, resin)


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Interface flange Tube retaining collars

Umbilical

Female connector

Resin filled Tube with flanged interface

Articulated bend limiter

Tube separator

Typical 5m Tube bundle clamp

Electrical cables

Figure 32– Subsea termination interface arrangement The outer steel or plastic tubes are separated from the centre tube by the insertion of a tapered cone over the centre tube and this “sprayed” tube configuration is resin encapsulated within a tubular compartment. To prevent the tubes from pulling out of the resin, collars are fillets welded to the tubes (see figure 32) in order to provide a bearing surface against which the resin is poured during assembly. In this way the compressive modulus of the resin rather than the bond strength of the resin to the tube limit the load (or tension) capability. The efforts applied to the umbilical are mainly taken by the interface flange, which recuperates the tension forces through the tube retaining collars and the moments through the bend limiters.


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3.7


Subsea bend restrictor

When an umbilical is unsupported over a large free span there exists the possibility of damaging the umbilical structure due to over-bending. Typical locations at which this problem may occur could be at the subsea connection points and J-tube exits. Fitting a device known as bending restrictor prevents over-stressing of the umbilical. A restrictor consists of a number of interlocking half rings, which are fastened together around the umbilical (see figures 33 and 34). The restrictor does not hinder the movement of the pipe until a pre-determined minimum bending radius is reached, at which point the restrictor elements lock. Entry funnel

Rigid shell

Clamp / ring fasteners fastener

Umbilical termination head

The minimum bending radius is determined by the clearance within the clamp

Bend restrictor

Figure 33 – Integrated service umbilical equipped with steel bend restrictor

Figure 34 – Bend restrictor schematic

The restrictor and not the umbilical subsequently carry additional external bending loads. The subsea bend restrictors can be either based on cathodically protected steel elements or conventional moulded elements. In the latter, the bend restrictor elements, or rings, are manufactured from a specific grade of polyurethane elastomer. The material is tough, semirigid and creeps resistant. The steel material is preferable to the plastic elastomer, with respect to preventing overbending of steel tube umbilicals. The steel bend restrictor also provides better definition of mechanical characteristics or improved strength. The subsea steel bend restrictor is purposely designed for each individual application and is provided with cathodic protection. The restrictor ring fasteners are not connected to a cathodic protection system and so they are supplied in highly corrosion resistant materials. Bending restrictors could be installed either onshore or (if reeling problems are expected) offshore prior to the laying operation.


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3.8


Topside bend stiffener

Dynamic umbilical may be secured to rigid structures such as fixed flanges mounted on top of I/J tube at the hang off platform, with or without emergency release connectors. The presence of environmental loads will subsequently cause the pipe to bend near this hang-off point. With respect to dynamic steel tube umbilicals, the greatest challenge to overcome is fatigue. And the most critical area with respect to fatigue is usually this interface area between umbilical and floating production system. The bending in combination with large axial loads may cause damage to the umbilical structure due to overbending. To prevent structure damage due to overbending the umbilical termination may be supplied with a dynamic bend stiffener, which protects the umbilical from the wave, currents and vessel motion induced bending in the interface area, and ensures the umbilical’s required design life. The bend stiffener has a single section of graduated profile non reinforced moulded polyurethane elastomer. This material is extremely tough yet flexible and suitable for extended service in a subsea or an above water marine environment. The topside bend limiter for dynamic steel tube umbilicals is a purpose built device. The bend limiter design is based on non-linear finite element calculations and given vessel motions / sea states. The typical parameters needed for the design of bend stiffener are: minimum and maximum axial top tension, maximum top deflection angle, umbilical bending stiffness and minimum bend radius requirement.

Bending stiffener

Figure 35 – Topside bend stiffener


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3.9


Topside termination system

Riser sections are terminated using a split flange hang off collar. Termination of the mechanical components is achieved by welding of the armour wires to a stepped collar, below the hang off point. The topside termination is mechanically terminated in the same manner as the subsea termination (see figure 36).

View X - X

Sput hang-off flange & bolting

Protective covers securing screws Tube bundle clamp

Female connectors Retaining collar

Armour wires welded to collar

X

Tube with flanged interface Pull-in head

X Ø324

Umbilical Heat shrink tape

Resin filled

Tube separator

Water blocking caps on electric cables

Tube retaining collars Piping connections

Figure 36 – Topside termination of steel tube termination

3.10 External corrosion protection The armour wire is protected by the galvanisation applied during manufacturing of the wire. No additional cathodic protection is proposed. Joints, terminations and hardware fabricated in carbon steel and permanently installed subsea, or permanently exposed to the splash zone are protected by zinc plating to BS 1706, Grade Fe Zn 10C/1A, hot dip galvanised or painted to subsea paint specification. Stainless steel are possible for optimum corrosion resistance. Carbon steel tube external corrosion control includes the traditional use of cathodic protection in conjunction with organic coatings and the use of metallic coatings which could provide both the cathodic protection and barrier coating corrosion control functions. Traditional cathodic protection techniques include (1) bracelet type anodes spaced at discrete distances along the steel tube elements, (2) large anodes installed on the seabed and connected to the umbilical at longer discrete distances, and (3) continuous ribbon type anode material installed within the umbilical during fabrication. The first two methods would not allow for proper current distribution to the steel tubes through and underneath the umbilical jacket roving. Although the ribbon anode material was designed for this concern, attenuation analyses indicated that the anode material would require an unrealistic number of electrical attachment points. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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Metallic coatings have been utilised for providing corrosion control in seawater immersion in the North Sea, and more recently in the Gulf of Mexico. Thermal sprayed aluminium meets all mechanical and corrosion requirements for steel tube. However, there is a concern around the ability to sustain a high rate of tubing production and economics. An extrusion process would be a more effective method to apply a metallic coating to the tubing with zinc as the coating material. This solution was used for zinc coated wires in complex mooring cables for Tension Leg Platforms. This design uses bitumen type blocking agent. The barrier coating and cathodic protection functions of a zinc alloy are a function of the alloy’s chemical composition. Zinc alloys typically used for cathodic protection in seawater are quite active and have poor barrier coating properties. Conversely alloys, which exhibit better barrier coating properties, have limited cathodic protection capabilities. A combination of these properties is required for long term corrosion control of steel umbilical elements.


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4.

TEST REQUIREMENT

4.1

General

To demonstrate that the functional core components and umbilical system will meet the performance requirements, a qualification/factory acceptance test program should be undertaken. This will cover material testing of each umbilical component through to umbilical performance verification.

4.2

Material qualification testing

The following typical test regime is performed on samples for qualification of functional core components to verify its performance according to the design specifications: ♦

♦

♦

Steel tube material

Criteria, purposes

- Mechanical tests (Yield, Tensile, Elongation)

Tension loads, strains,

- Hardness test

Fatigues, cracks,

- Pitting corrosion test

Corrosion, life cycle,

- Flattening test - Flaring test

Loading, crushing, Fire resistant,

- Ultrasonic testing

Tension loads, fatigues,

- Eddy current test

Fatigues, cracks,

- Burst test - Proof pressure test

safety limit to tensile stress, safety limit to yield stress,

Electric cables - DC conductor resistance

line integrity,

- Insulation resistance

depth pressure, water-proof,

- High voltage DC

Function capabilities

Data transmissions - Check of data transmission performances which are typically: ⇒ between 1200 and 4800 bits per second (depending on total length) for a conventional copper wire signal, associated with a bit error of less than 1 in 105 bits. ⇒ about 55Mb.s-1 for optical cables and bit error rates of better than 10-9.


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4.3


Umbilical design qualification testing

Sample lengths of prototype umbilical manufactured and tested prior to the manufacture of the final umbilical will prove mechanical performance of the umbilical design. The following tests are performed on dynamic umbilical prototype samples in the manufacturing facility: -

Tensile breaking strength

-

Torsional stability

-

Flex fatigue of umbilical and topside hang-off arrangement

-

Crush resistance test (installation parameters – see chapter 5)

The steel umbilical prototype samples will include butt welded tube sections in order to verify the integrity of the welds under flex fatigue conditions. The performance criteria and cycles performed will be mutually agreed between umbilical manufacturer and operator.

4.4

Acceptance testing

Extensive testing is carried out by the umbilical manufacturer at all stages of manufacture to ensure the finished products meet the required acceptance criteria and are fit for purpose. The following tests are undertaken: ♦

Steel tubes and thermoplastic hoses (full production lengths) - Visual inspection - Dimensional checks - Burst pressure test (samples only) - Proof pressure test (1.5 * design pressure)

♦

Electric cables -

Hydrostatic testing @ 35 bar.g of insulated conductors

-

DC conductor resistance: consists in measuring electrical cable conductor resistance. The conductor resistance measurements shall be corrected for temperature and referred to 20°C. The accuracy of the conductor resistance measurements shall be in milliohm. Temperature correction and accepted criteria shall be in accordance with IEC publication 228

-

Insulation resistance consists in measuring insulation resistance between conductors and to earth. Test voltage shall be minimum 500 volt DC and minimum acceptable insulation resistance shall be e.g. 1000 Mohms/km.

-

High voltage DC to verify the electric cable function performance

-

Time domain reflectometry: this test is carried out to establish the cable signature and shall be used for detection of possible changes in this signature due to stress, damages, etc. during the fabrication and installation phases.


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♦


Umbilical

The following tests will be carried out on the finished umbilical before load out and those marked *, shall be repeated (as required) after loading onto the shipping/installation reel, during the installation phase and the subsea pre-commissioning phase. Results should be comparable to the previously performed tests (i.e. before load-out). -

Electrical cables DC conductor resistance* (minimum one loop during installation) Insulation resistance * High voltage DC Time domain reflectometry *

-

Hydraulic tests Proof pressure test * and decay test (hoses) Proof pressure test * (steel tubes) Flow rate test in turbulent conditions (steel tubes and hoses) Dimensional and visual (steel tubes and hoses) Hydraulic fluid cleanliness (steel tubes and hoses) *

-

Data transmissions Check of data transmission performances

Notes:

♦ The umbilical hydraulic lines will be pressure tested using filtered fresh water or final fluids as required, flushed and cleaned to meet or exceed the requirements of NAS 1638, Class 6 (Hydraulic Control), Class 8 (Scale) and class 12 (Chemical/inhibitor). The umbilical hydraulic lines will be delivered fluid filled, prior to load-out. ♦ Procedures for maintenance of the stored umbilical, including the frequency of fluid replenishment, pressure monitoring, etc. should be generated. ♦ The pressure test is as follows:

FAT: 1.5 times design pressure After load out: 1.25 times design pressure

After laying: 1 time design pressure

(Design Pressure = maximum allowable internal pressure) ♦ After installation and as part of the pre-commissioning phase, all test pressures refer to the pressure at seabed, which shall equal the design pressure. Therefore test pressures at surface (vessels or FPSO) must be defined according to the hydrostatic head relevant to the water depth. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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4.5


Extent of flushing, pressure testing, cleaning & preservation

The requirements for flushing, pressure testing, cleaning and preservation for specific umbilical fluid lines are listed in table 01:

Line Type

Flushing &Cleaning

Pressure test

Prefab

Prefab

FAT

Load out

Chemical / service lines

X

X

X

X

Hydraulic lines

X

X

X

X

Pickling *

Hot oil flushing

Flow test

Cleanliness

Preservation

Prefab

FAT

FAT

FAT

FAT

Load out

X

X

X

X

Load out

X

X

X

X

X

X

* see Table 02, section 6.1, thermoplastic hose

Table 01 – Test requirements summary table

After incoming inspection and dimensional control a foam pig is driven through the steel tubes by dry filtered air, to verify cleanliness and remove any contamination before welding. During welding (& reeling onto storage carousel) the tubing shall be equipped with special end fittings for flushing and hydraulic pressure testing. After pressure testing the tubing shall be thoroughly drained and dried by means of a wiper pig driven through the system by dry filtered air. The operation shall be repeated until the system is clean and dry (e.g. NAS 1638). Immediately after drying, blind caps shall be mounted on the end fittings for protection during storage and transportation. After assembly and welding into complete umbilical, another hydraulic pressure testing will be required for all lines. When the pressure testing has been accepted and recorded, chemical cleaning (pickling) shall follow for the hydraulic lines. The chemical cleaning will be executed in three steps: acid cleaning, flushing and drying. In addition the hydraulic lines shall be flushed with hot oil. During this operation a cleanliness verification and water content examination shall be executed by particle counting of the fluid in accordance with NAS 1638 Class 6.


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5.


5.1

General

Deepwater field development uses subsea drilled and completed wells tied back to fixed structures in shallower water or floating production systems in deep waters. The tie back connections may be performed directly or through a subsea manifold. These subsea trees are monitored and controlled via umbilicals suspended in a catenary shape and protected at the splash zones by I/J tubes fixed to the structures as illustrated in figure 37. Floating Production System

1. Umbilical connecting FPS to subsea structure

Hang off platform Sea level Bend Stiffener

Deep water Subsea termination assembly Riser Splice (if any) Umbilical

Subsea Structure

Seabed

Laydown target area Production Platform

2. Umbilical connecting ‘host’ platform to subsea structure Attachment point

Sea level

J tube Shallow water Seabed

Bellmouth Deep water Subsea termination assembly Umbilical

Subsea Structure

Laydown target area

Figure 37 – Different umbilical configurations in deepwater field development Umbilicals are installed from an umbilical/flexible pipe installation vessel and can be deployed from two distinct umbilical laying spreads, depending on the line structure limitation and the lay tensions : ♦ in-line two-tracks tensioners ♦ or directly from the storage reel Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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For deepwater applications, steel tube umbilicals can have a large size of over 100mm OD (i.e. 110 mm – 180 mm) and high lay tensions varying between 30 tons and up to 100 tons at 2000m water depth. Based on the umbilical crush resistance test (see section 4.3) and a typical usage factor of 0.67 (or safety factor, refer to API 17 J), an allowable compression load is defined. Both, umbilical lay tension and allowable compression load will determine the required (dualtrack) tensioner contact length or the number of tensioners to provide the equivalent contact length. When the required contact length is higher than 10 m – 12 m, there is a clear advantage to lay the umbilical directly from the storage reel, which must be rated for the lay tensions. As for rigid pipe, the steel tube umbilical must be laid as per the rules for submarine pipeline systems, and more specifically in accordance with the following criteria: ♦ Maximum 2% cumulative strains (reeling, unreeling, straightening, etc) ♦ Large radius overboarding chutes (e.g. 14 m) to keep the ‘as laid’ umbilical steel tubes within the elastic domain (or less than 1% residual strain), with typical 3°-5° departure angle Static umbilical can also be integrated in a flowline bundle and installed by the towing method. With regard to the repair topic, the only known method is to recover to surface the termination heads or the umbilical for repair; there is no underwater repair technique alternative. The following sections will cover the current umbilical installation method using DP vessel equipped with suitable equipment for the work and related laying technique and procedures.


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5.2


Laying equipment

Umbilicals can be laid directly from a storage reel or via a tensioner system and associated carousel basket (see figure 39) installed on main deck or inside the installation vessel. The umbilical is deployed and over-boarded from a stern laying wheel, similar in shape and dimensions to the flexible one (i.e. CSO Sunrise 2000 in figure 38), or from an over-boarding chute located at the stern or on the side of the vessel as illustrated in figure 39.

Laying wheel

In-line tensioners

Figure 38 – CSO Sunrise 2000m flexible & umbilical lay vessel

Overboarding chute (e.g. 14 m radius)

Straightener/spooler

Umbilical line

Horizontal powered reel Dual tensioner

Second end termination

Aligner

Work platform

First end termination

Carousel

Spooling arm

Carousel

Figure 39 – Umbilical laying spread general arrangement


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The umbilical lines are stored in a rotating basket in one or several segments and are routed towards the tensioning system via a spooling and deflector system. A straightening function will be added to the spooling system in case of integrated service umbilical deployment. When umbilicals are laid directly from the storage reel rated to hold the full catenary tension, the line is spooled out from the top of the reel with a spooling device. The umbilical tensioning spread consists of individual in line tensioners over the working deck. Both the umbilical laying reel with associated spooling system and the umbilical tensioning spread are controlled from the operation control room, in synchronization with deployment of the flowlines in case of a dual lay. The storage basket and the associated spooling system is operated generally from an individual control cabin. The umbilical abandonment is performed with a winch fitted with adequate cable length and size related to water depth and laying tension. Abandonment of the umbilical line on the seabed is achieved using a ROV remotely controlled disconnector or an acoustic release hydraulic shackle. A deck crane (or A-frame) provides a direct access over the outside of the umbilical laying wheel or overboarding chute. The proper outreach of the crane facilitates the overboarding of umbilical connection or large termination unit. 5.3

Laying methods and procedures

5.3.1. General Umbilicals are laid using one of the following typical methods: 1.

Umbilical is initiated at the manifold with a stab and hinge over connection or a pull-in/connection method and terminated near the subsea well with a second end lay down sled (i.e. infield umbilical connection from manifold to satellite well). The connection between the umbilical and the subsea well is later made using a combination of the following tie-in methods: (1) rigid or a flexible jumper, (2) junction plates and (3) flying leads (see figure 40).

2.

Umbilical is initiated at the manifold with a stab and hinge over connection or a pull-in/connection method. It is laid in the direction to the fixed or floating production system and pulled through an I/J tube or cross hauled from the laying vessel to the floating production vessel (see figure 41).

3.

Umbilical can also be initiated at the fixed or floating production system and terminated near the subsea structure with a second end umbilical termination assembly (i.e. termination head, lay down sled, umbilical termination unit, etc.). A pull-in and connection tool operated by ROV may be used to connect the umbilical to the subsea structure (see figure 42).

For further information on connection technique please refer to Document “Tie-in Methods” [reference 05] in Deepwater Field Development Reference Book. The fabricated umbilical length must be accurately determined for installation purpose based on: ♦ On site route survey (seabed bathymetry, pockmarks, seabed debris and obstruction, etc)

♦ Overlength (typically 2% - 5%) to mitigate for measurement accuracies of baselines (e.g. DGPS, acoustic) and electronic equipments. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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For steel tube umbilical and for deepwater installation, the internal fluid temperature drop from surface (up to 40°C in West Africa) to seafloor at 4°C will induce fluid volume reduction. In which case, potential tube collapse, under hydrostatic pressure at seabed must be addressed, or fluid volume compensation must be provided during the installation sequences. The installation sequences associated with the above umbilical laying methods are further described in the following section.

5.3.2. Installation procedures 5.3.2.1

Umbilical installation between subsea manifold and X-tree

Method 1 Ö The installation sequence would consist of the following phases (see figure 40): 1.

The first end of the umbilical is initiated with a stab & hinge-over connector at the subsea manifold equipped with a stab & hinge-over receiver.

2.

When the stab & hinge-over connector is fully engaged and locked in its receiver, the installation vessel moves ahead slowly to perform the hinge-over operation.

3.

During the hinge-over operation, the correct rotation of the connector and landing of umbilical on seabed is monitored by ROV.

4.

On completion of hinge-over phase, normal umbilical laying continues until lowering of second end termination unit or sled on seabed.

5.

Once the sled is laid down in the target area, its position is confirmed by ROV and acoustic metrology.

6.

When the sled abandonment and disconnection of A&R winch cable are completed, the connection of the umbilical to the subsea structure is performed by ROV using flying leads terminated with junction plates.

Note : As part of above step 4, when approaching the target area from a distance of 2 – 3 times the water depth, the remaining umbilical length (in surface) is to be cross checked with the remaining lay distance (by means of acoustic baseline). This will allow the umbilical over length to be stored in curves on the seafloor, prior to the lay-down of the sled/umbilical termination unit in the target area.


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Umbilical laying spread

Lay vessel

Umbilical terminated with stab&hingeover connector

Subsea tree

Subsea manifold

Receiver

1

UMBILICAL LOWERING

2

CONNECTOR STAB IN

Umbilical termination unit

Target area

3

4

CONNECTOR HINGE OVER

UMBILICAL LAY AWAY

Flying lead

Weak link

Junction plate Umbilical termination unit Subsea tree Umbilical

5

6

SLED LAY DOWN

UMBILICAL CONNECTION

Figure 40 – Umbilical installation from subsea manifold to subsea tree Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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5.3.2.2


Umbilical installation with first end initiation at subsea structure

Method 2 Ö The installation procedure would consist of the following phases (see figure 41): 1. Lowering of the umbilical with its stab & hinge-over connector using the umbilical laying spread located at the stern of installation vessel. 2. Stab and lock the connector in the receiver mounted on the subsea structure. 3. Move the vessel in the laying direction while paying out on umbilical to perform the hinge-over operation. 4. On completion of hinge-over operation, ROV will check the correct landing of the umbilical on seabed before resuming the normal umbilical laying operation. Umbilical is paid out until the vessel takes position for the transfer of umbilical to the floater. 5. When the transfer cable is recovered from the floater, connect the pull-in line to the pull-in head mounted on the umbilical and start the transfer of the umbilical to the floater. 6. Once load transfer is completed, recover A&R winch cable, resume pulling the umbilical through I/J tube and secure the umbilical to the hang off platform. Note: The same note for umbilical over-length (see 5.3.2.1) is applicable during above step 4.


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Lay vessel

Umbilical terminated with stab&hingeover connector Subsea structure

Receiver

1

UMBILICAL LOWERING

2

CONNECTOR STAB IN

Lay direction

3

4

CONNECTOR HINGE OVER

UMBILICAL LAY AWAY hang off platform

Pull-in winch J tube


Bend stiffener Umbilical termination head

Transfer cable

5

UMBILICAL CROSS HAUL

Umbilical

6

UMBILICAL HANG-OFF ON FLOATER

Figure 41 – Umbilical installation with first end initiation at subsea structure


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5.3.2.3


Umbilical installation with first end initiation at floater

Method 3 Ö The installation sequence would consist of the following phases (see figure 42) : 1. A transfer cable is passed from the floating production system to the installation vessel by means of ROV. 2. The first end umbilical termination is transferred to the floater with the dynamic part of the umbilical by pulling it through the I/J tube attached to the floater structure. 3. The first end termination is secured to the hang off platform while paying out of the umbilical continues. 4. Normal umbilical laying operation continues until the lowering of the second end umbilical termination on seabed. 5. On completion of second end umbilical termination lay down in target area, ROV will confirm its position before removing the A&R winch cable. 6. If the umbilical is terminated with a termination head, the tie-in method will consist in first performing the pull –in of the termination head in the subsea structure then its connection to the structure by means of ROV operated tools or running tools to be deployed from the surface vessel. If the umbilical is terminated with a termination unit/lay down sled, the tie-in method is performed by ROV using jumpers and flying leads. Note: The same note for umbilical over-length (see 5.3.2.1) is applicable during above step 4.


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Floating production system Umbilical

Lay vessel Sea level Transfer cable

Transfer cable

ROV First end termination

Seabed

1

2

TRANSFER CABLE RECOVERY

UMBILICAL CROSS HAUL

Attachment point

Lay away direction

Second end termination

Umbilical

Subsea structure

3

UMBILICAL ATTACHMENT & LAY AWAY

4

Target area SECOND END TERMINATION LOWERING

ROV operated connection tool Pull in winch

Termination head

5

UMBILICAL TERMINATION HEAD LAY DOWN

6

UMBILICAL PULL IN & CONNECTION

Figure 42 – Umbilical installation with first end initiation at floater


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6.


6.1

Thermoplastic hose umbilical

Most of the umbilicals fabricated to date have used thermoplastic tubes as fluid carriers. Frequently, the electrical conductors are installed separately, but they have been included in some designs, usually termed "electrohydraulic umbilicals". Separate control and chemical umbilicals were often chosen because of the possible incompatibility between one of the injected chemicals and the hose liner. Such an incompatibility could then result in a chemical attack of the critical element i.e. hydraulic hoses and electric cable insulation with the subsequent loss of control and a total field shutdown. Although chemical compatibility testing was carried out to verify the suitability of the hose liner for transporting the specific chemicals (and alternatives) there was always the risk that an incompatible chemical could be introduced over the field life leading to failure. In addition, the accelerated ageing tests in which the hose liner material is tested with the chemicals at elevated temperatures, although satisfactory, cannot be considered as a fully guaranteed guide to long term deterioration. They are useful in that they will identify most incompatibility problems in a reasonable time. In the umbilical design, there is a tendency to request duplication of the electrical components, both power and signal. In addition, there is often a requirement to design the umbilical to minimize the cross-sectional area. This may be because of limitations in the I/J tube diameter or handling capacity limitations of transportation or lay vessel reel/carousel. Power conductors, signal pairs and hydraulic hoses of different diameters and with different elasticity properties are then bundled together using either a planetary machine resulting in a helical lay-up or an alternate clockwise-anticlockwise method known as S-Z. This latter method has a distinct advantage in that it can lay-up longer lengths without joints because of the size limitations of cable drums which can be accommodated on planetary machines. In addition to the components having different elasticity, the back tensions of each component as they are transferred from the reels or drums to the lay-up machine may be unequal. This residual tension combined with the effects of dynamic forces due to installation vessel motions, the compressive forces due to hydrostatic pressure and potential compression due to the near position in free hanging configuration, may lead to the breaking of electrical cables. Electro-hydraulic umbilical riser should be designed to withstand dynamic loads induced by FPS. Such umbilical would have a very high degree of radial symmetry and the lay-up angles for all conductor cables and hoses would be high to give the necessary flexibility. They would therefore have a larger diameter and would occupy much more machine time in manufacture than the equivalent static product. As a result, they would be typically 50% more expensive than an umbilical designed for static use. During the early period of subsea production system implementation (e.g. 80’s), compatibility was not considered to be a major problem, particularly with Polyamide 11, because of its outstanding chemical resistance. Where compatibility evaluations were undertaken, these were performed using dumbbell samples of liner material immersed in the test fluid at elevated temperature (usually 70°C or 100°C). The dumbbell was manufactured nominally 2 mm thick from a sheet of material produced by means of an injection moulding process. Life prediction was generally based on the half-life principle, whereby the time for the elongation at break to reduce to the 50% level was determined. This prediction that the rate of a chemical reaction doubles for every 10°C rise in temperature, was used to extrapolate the minimum service life at operating temperature.


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For example, if a series of tests performed on liner material immersed in a fluid at 70°C shows that it takes 7 months for the elongation at break to reduce to half its original value, the predicted life at 20°C would be extrapolated as shown in table 02:

Temperature °C

Life (Years/Months)

70

0y 7m

60

1y 2m

50

2y 4m

40

4y 8m

30

9y 4m

20

18y 8m

Table 02 – Prediction life of liner material (50% life improvement for every 10°C reduction)

The increasing use of subsea production systems and increasing offset distances and the need to inject well service chemicals, has resulted in a wider range of control fluids and a proliferation of well service fluids. These fluids tend to be mixtures of chemicals contained within a solvent base. At this time it had been observed that one of the hose liner materials exhibited considerable anisotropic features and, it was felt, that perhaps the dumbbell test method may not necessarily be a realistic test for such materials, particularly, with fluids of a "cocktail" nature. Whilst recognising the simplicity and low cost features of the dumbbell test, a more elaborate yet simple low cost test was employed to address the anisotropic aspects. Instead of immersing dumbbells in the fluid at ambient pressure, samples of extruded tube were immersed and instead of measuring the elongation at break as a function of time, the burst pressure of the tube was monitored with time. In order to compare the sample immersion testing with pressurised hose testing, the pressure cycling compatibility test method was developed and consists in filling the hoses with control fluids, which would be subject to pressure cycling at elevated temperatures. The qualification programme for a standard hydrostatic hose test in accordance with SAE J343d rules for hoses up to 10,000 psi rated working pressure is as follows: •

Impulse (200,000 cycles at 135% of rated working pressure at 93°C)

•

Leakage (70% of minimum burst pressure for 5 minutes)

•

Burst (minimum 4 times the rated working pressure)

•

Change in length (±2% at rated working pressure)

Stability of the service fluid is an important consideration and any instability could give rise to localised incompatibility with a hydraulic line. Stability testing of the service fluid should be undertaken to qualify a fluid and to highlight any potential problem areas. It is understood that draft API 17F specification, "Subsea Control Systems", will include such tests. The same consideration needs to be given to well service chemicals where separations of products are not uncommon. Where hydraulic lines are installed in a vertical shape, e.g. J-tube, Floating Production System, the potential for separation is greatly increased. The impact of any fluid Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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modifications, however minor, should be fully evaluated before being introduced into a hydraulic line. Regardless of the materials of construction of a hydraulic line (polymeric, elastomeric or metallic), compatibility testing should be performed with the actual line design to be used in service, in order to minimise the risk of problems arising after manufacture of the umbilical system. With thermoplastic polyester, the small volumes of additives (lubricant, biocide, etc.) in the control fluid can have a significant effect on the rate of chemical reaction between the fluids and the polymer. For polymeric hose liners, the rate of increase in chemical reaction is more severe when compared with the historical methods based on dumbbell and tube samples, accelerated without stress. For polyamide 11, the material would be expected to withstand chemical compatibility and stress ageing. It has been demonstrated that a service life in excess of 20 years for temperature up to 40°C is possible; there are examples of at least 16 years extended service life experience for typical North Sea operational temperatures.


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Polymer mechanical properties are shown in under table 03: PROPERTIES

UNITS

Specific gravity Tensile strength at break Elongation at break Modulus of elasticity

ASTM

HDPe

XLPe

Polyamide 11

Thermoplastic Polyester

Kg/dm3

D 792

0.946

O.95

1.05

1.22

MPa

D 638

30

30

50

41

%

D 638

>350

250

350

420

MPa

D 790

700

800

300

300

64

55

63

63

Shore hardness

Shore d


W/m.K

C 177

0.32

0.32

0.33

0.22

°C

D 3222

126

N.A.

180

184

Volume resistivity

Ohm/cm

D 257

1014

1014

1011

1013

Electric strength

KV/mm

D 1491

-

-

23

16

%

D 570

<0.01

<0.01

0.2

0.2

Good

Good

Good

Good

Melting point

Resistance gain 23-C-24h Resistance to sunlight Resistance to weak acids

D 543

Very good

Very good

Very good

Very good

Resistance to strong acids

D 543

Accord. to acids

Accord. to acids

Poor

Poor

Resistance to strong bases

D 543

Very good

Very good

Good

Fair

Resistance to solvents

D 543

Good

Good

Attacked by phenols

Attacked by phenols

Up to 60°C

Up to 90°C

Up to 100°C

Good

Resistance to water

Up to 60°C

Up to 90°C

Up to 70°C

Poor

Resistance to methanol

Up to 60°C

Very Good

Up to 50°C

Poor

Resistance to without water

crude

oil

Table 03: Polymer mechanical properties


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For methanol, the following table 04 shows the permeation rates which have been measured for Polyamide 11 and Thermoplastic Polyester at atmospheric pressure:

Temperature

2

Permeation rate (g.m /mm/day)

(°C)

Polyamide 11

Thermoplastic Polyester

50

190

150

40

115

100

23

40

22

4

13.5

5

Table 04 – Permeation rate of methanol in Polyamide 11 and Thermoplastic Polyester (69 bar)

The permeation rate of methanol in XLPe lining material for internal pressures of 344 bar and 69 bar are presented in the following table 05:

Temperature

2

Permeation rate (g.m /mm/day)

(°C)

69 bar (1000 psi)

344 bar (5000 psi)

60

1.35

1.81

20

0.078

1.11

4

0.018

0.079

Table 05 – Permeation rate of methanol in XLPe Remarks : Comparing the permeation at 4°C and 69 bar, of the XLPe to the Polyamide 11, it can be seen that the permeation rate through the XLPe is 750 times less than that of the Polyamide.


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6.2



Subsea requirements have changed considerably over the past 15 years. Deeper waters, longer offsets, higher reservoir pressures and temperatures - combined with an increased use of chemicals for paraffin, hydrate and corrosion control - are too demanding for traditional thermoplastic umbilicals and have resulted to the development of steel tube umbilicals. Thermoplastic umbilicals cannot sustain operating pressure and temperatures beyond a certain level (e.g. 5000psi, 60°C). Response time is slow due to volumetric expansion. There are also problems relating to fluid contamination and chemical permeation, along with the fact that some umbilicals are difficult to clean and keep clean due to the ligamers leeching into the conveyed fluid. Additionally, end fittings are swaged onto plastic hose and are not reliable at high pressure or under the abrasiveness of well control chemicals. A viable alternative to thermoplastic umbilicals is steel tube umbilicals, which offer many advantages over plastic materials. Response times increase dramatically. Much higher internal pressures at large diameters (1” at 15,000psi, for example) are achievable. Fluid contamination and chemical permeation are drastically reduced. Steel tube umbilicals are also easily cleaned and they remain clean. The tubing end fittings are welded, ensuring their integrity under pressure and the corrosiveness of well control chemicals. Water depths of current interest, limit the use of thermoplastic tubes, since they tend to collapse. Metal tubes can be sized for collapse and will not meet a limit until well beyond 10,000 feet (3000 m) for the range of diameter considered for umbilical applications. Metal tube umbilicals of reasonable size should not be limited by collapse. The steel tube umbilical design allows the steel tubes to carry the axial and compressive loads, which eliminates the need for a costly and cumbersome armour wire package that can unravel or "birdcage". The steel tube umbilicals are also lighter and have a smaller outside diameter than the equivalent thermoplastic umbilicals while maintaining favorable minimum bend radii and displaying better on bottom stability. Yet, for all the benefits over conventional thermoplastic systems, the steel tube umbilical is dealing with proven technology, and not a "new" product. Steel tube umbilicals evolved from readily familiar pipeline, piping and pressure vessel and flowline bundle-type systems. The end fitting hardware, the J-tube hang-off assembly, bullnose, subsea termination, bend restrictors, bend limiters – all are conventional, field proven equipment systems. Metal tubes offer advantages including: (1) impermeability to methanol, (2) the abilities to withstand high internal and external pressure, (3) robustness of the tubes without armoring, (4) potential reduction in umbilical cross section complexity and, in some cases, (5) better compatibility with the working fluids. However, there are still engineering considerations that must be addressed regarding metal tube umbilicals, such as internal and external corrosion and, in the case of dynamic applications, fatigue performance of tubulars and end terminations and plastic straining during umbilical fabrication and handling. Furthermore, although fabrication can be accomplished using techniques similar to those for thermoplastic umbilicals, the equipment needed are different, in some cases requiring extensive modifications or completely new machinery and thus involving high steel tube umbilical procurement cost.


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The following considerations should be addressed in the design of dynamic umbilical: •

Fatigue life of material

•

Attachment to the FPS, including design and performance of a bend stiffener

•

Fatigue and strength of electrical conductors, if used

•

Wear and abrasion between tubular elements

Note: Allowing the electrical conductors to move axially, usually by providing lubricants and selecting proper insulation material, is the key to increase their fatigue life.

For dynamic applications the dynamic behaviour and fatigue life of the umbilical are two of the most important characteristics of the design. There are two critical locations that may be deficient in fatigue life and must be examined carefully: the region near the point where the umbilical contacts the seafloor (the “touchdown point or sag-bend radius”) and the hang-off level at FPS. The analysis that is required to assess fatigue life is both complex and timeconsuming. There are two conditions that create fatigue loading: (1) vortex induced vibrations due to current and (2) FPS motions due to wind, wave and current conditions. One critical element in the design of a dynamic umbilical is the bend stiffener. This device is an integral part of the top support and serves to limit extreme stresses, due to static offset of the floating production system or strong currents, and reduce the cyclic stresses which contribute to fatigue. As part of the material selection, the key requirement is maintaining pressure integrity and internal cleanliness for the expected life of the project. Along with the mechanical requirements, the material must resist external corrosion in seawater and mud as well as internal corrosion due to water-based hydraulic fluids and chemical (e.g. methanol). The tubes within an umbilical are surrounded by seawater. The key parameters of seawater are temperature, oxygen concentration and pH. Another aspect of exterior environment is cathodic protection. Even though it may not be required for the umbilical material, cathodic protection may be required on other parts of the system. It is difficult to isolate these components from the umbilical. In some cases, cathodic protection not properly designed, can lead to hydrogen embrittlement, the degradation of material properties caused when hydrogen is absorbed. Besides resisting corrosion on the inside, the umbilical material must not significantly change the hydraulic fluid characteristics and in particular the cleanliness of the hydraulic fluid, which must remain near NAS Class 6, since material particle can foul or plug the control valves in the subsea control system. To meet these conditions, three alternative tube materials were considered: 1. low-alloy carbon-steel 2. super-duplex stainless steel 3. titanium alloy


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6.2.1. Carbon steel: Carbon steel offer significant cost savings in comparison with other materials but it rusts in seawater. This corrosion can be controlled with coating and/or cathodic protection (CP). Four options are possible: (1) traditional coating and sacrificial anodes, (2) a thermally sprayed aluminium (TSA) coating, (3) aluminium sheathing and (4) Zinc coating. Traditional cathodic protection with sacrificial anodes is not a good option for two reasons. First, it is difficult to make reliable anode connections to the umbilical. Second, attaching sacrificial anodes significantly increases the laying time, and hence the laying cost. TSA acts both as a barrier coating, as well as a sacrificial anode. These coating have been used in the past, for example as a tendon coating on Conoco's Hutton TLP. There is a significant difference between spraying large diameter pipe and small diameter umbilical tubes. Small diameters decrease the efficiency of the spray process: (most of the sprayed metal does not coat the target and is lost). In addition, it is more difficult to achieve a uniform coating thickness. The concept of aluminium sheathing is to create an outer aluminium tube around an inner carbon steel tube with a crevice between the two. There would be no metallurgical bond between the aluminium and the steel. To evaluate the aluminium corrosion resistance in seawater, one test specimen had holes drilled through the aluminium sheath, exposing the crevice between the steel and aluminium to seawater. Rapid corrosion of steel tube caused this alternative to be rejected as a means of protecting carbon steel from corrosion in seawater. The Zinc cladding process was used for the Shell Mensa project (carbon steel tube umbilicals) in which the zinc is metallurgically bonded to the substrate. Similarly to TSA, Zinc coating acts as both a barrier coating and a cathodic protection. This option was selected for Mensa as a reasonably economic solution due to the large size and quantity of steel tubes. Internal corrosion may occur in carbon steel tubes containing either hydraulic fluid or methanol. Pure, de-oxygenated hydraulic fluid is not corrosive to carbon steel; however, above a small concentration of seawater, pitting can be significant. The pitting of typical steel (e.g. AISI 4140) is a function of the seawater concentration in a typical water-based hydraulic fluid. Successful use of carbon steel requires that the concentration of seawater be kept below 5%. Although seawater may enter the line through negligence, it is more common for seawater to be ingested during coupling. Some have suggested that as much as 1 cm3 of seawater enter each line during coupling. De-aerated methanol does not promote corrosion in steel. Without oxygen, corrosion rates in pure methanol and other corrosive agents are extremely low, about 0.02 mpy (millimeter per year). At standard temperature and pressure, methanol may contain up to 45ppm dissolved oxygen, whereas water can contain only 5-6 ppm. Consequently, the corrosion rate is greater in aerated methanol. Some tests have reported corrosion rates on the order of 0.1 mpy in 90% methanol 10% water solution saturated with oxygen.


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6.2.2. Duplex and Super Duplex Stainless Steel Duplex and super duplex tubing has been used for umbilicals in the North Sea. Duplex steels are composed of two phases, austenite and ferrite, in a roughly 50/50 ratio. In superduplexes, the key elements providing corrosion resistance are chromium, molybdenum, nitrogen and tungsten (not all super-duplexes contain tungsten). Two issues are to be considered when evaluating the performance of duplex and superduplex tubes in seawater: pitting, and hydrogen embrittlement due to cathodic protection. Although duplex and super duplex materials perform well on standard pitting tests, these materials are susceptible to pitting in natural seawater. Local corrosion rates can be observed after exposing different samples to natural seawater for periods from several months to several years. The benefit of additional molybdenum, nitrogen and tungsten in super-duplex is demonstrated by a decrease in the pitting rate from 22 Cr duplex to 25 Cr duplex. Increased alloying on super-duplex increases the risk of forming σ-phase, a third phase with very poor mechanical properties. Care must be taken to prevent the formation of σ-phase when welding and heat treating these alloys. Good inspection procedures are also required. The use of proper welding and inspection procedures overcomes the problem of hydrogen embrittlement of the super-duplex welds. The good experience with these alloys in the North sea demonstrated their internal corrosion resistance to water based hydraulic fluids, and to methanol.

6.2.3. Titanium alloy With decreased demand for titanium in military applications, a decrease in titanium prices was anticipated. Consequently, the use of titanium grade 12 tubing can also be considered. Grade 12 titanium is a duplex alloy, consisting of α and β phases. There are two key issues: (1) stress corrosion cracking in methanol (SCC), and (2) resistance to cathodic protection. Titanium alloys can be susceptible to methanol-induced SCC. The addition of water to methanol can inhibit or prevent this from happening. Based on fracture mechanics tests, the minimum quantity of water required to prevent methanol-SCC in titanium grade 12 is 2%. Titanium grade 12 tubing in seawater does not require cathodic protection. However, hydrogen embrittlement had been observed in the α phase, such as grade 9. Titanium alloys are susceptible to embrittlement when exposed to cathodic protection, and to use this material, successful mitigation strategies must be adopted.

6.2.4. Summary Material

Key issues

Carbon steel

Corrosion

Duplex and super duplex

• •

Pitting Hydrogen embrittlement of the welds

Titanium

• •

Stress Corrosion Cracking in methanol Resistance to cathodic protection

Table 06 – Material key issues Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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7.


7.1

Thermoplastic umbilicals

The main advantages of thermoplastic hoses compared to steel tubes are as follows: •

Less expensive solution (typical manufacturing equipment, etc.)

•

Ease of handling, storage and installation due to low minimum bending radius

The disadvantages of the thermoplastic umbilicals with reference to the steel tube umbilicals and ISU are further explained in the following sections.

7.2


The following summarises what are considered to be the main advantages of metal tubes as service and hydraulic lines compared to thermoplastic hoses: 1. Fluid (methanol) permeation has been eliminated 2. Fluid compatibility problems have been reduced 3. Collapse resistance is drastically increased 4. Favourable response characteristics, especially for long length umbilicals 5. No mechanical effect on other umbilical elements when pressurising 6. Higher weight/diameter ratio gives improved dynamic and seabed stability 7. Maximum umbilical manufacturing length without factory jointing is increased, as tube strings are jointed by welding in the laying up process 8. Cost effective solution (life of field) for better dynamic umbilicals for ultra deepwater field developments The main disadvantages of steel tube umbilicals are: 1. Increased minimum bending radius, limitation in storage lengths, and limit the dynamic application to certain configurations 2. Limitation in recovery cycle (e.g. for repair) as this will involve plastic strains. 3. Limit to super-duplex tube length, resulting in many butt welds and associated radiography/corrosion testing 4. Attack by sulphide reducing bacteria on super duplex butt welded joints (e.g. BP ETAP, Shell ETAP, BP Troika) 5. Possible carbon steel longitudinal seam failure (e.g. Shell Mensa) 6. Risks of cathodic delamination of sheathing from carbon steel tubes leading to localised corrosion cells 7. More onerous flushing requirements (steel tubes are difficult to clean). Loosen particles or welding scale (e.g. by bending during installation) are potential risks for control valves. 8. Increased weight during deep water installation 9. Super duplex corrodes in seawater above 55°C, limiting use for hot water flushing and gas lift Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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Three metal materials are thought to be candidates for umbilical applications: carbon steel, stainless steel and titanium. Each of these has advantages and disadvantages. Carbon steel is the least expensive material, but corrosion and fluid compatibility must be addressed to assure adequate service life. Carbon steel can be made in continuous lengths, which tends to lower fabrication costs. Stainless steel, usually "duplex" or "super duplex" alloys, are more expensive, are not currently made in continuous lengths, but have better corrosion properties. Titanium is compatible with most fluids, can be made in continuous lengths, but is also expensive. Further, some titanium alloys must be used with care since they are affected adversely by anhydrous methanol and form brittle titanium hybrids under certain conditions of cathodic protection.

7.3

Integrated Service Umbilical

Compared to thermoplastic umbilicals, an integrated service umbilical has several advantages. The most important of these are: •

Improved chemical fluid compatibility. Super duplex steel is compatible with all commonly used injection fluids

•

No limit with respect to internal/external pressure. The tubing is individually dimensioned for each specification

•

The tubular expansion is limited and will not change over the years. The hydraulic response time will not alter over the years

•

No permeability of fluids through the steel tube walls

•

No migration of injection fluids

•

Improved internal tube cleanliness

•

Increased and predictable design lifetime

•

Not exposed to ageing/degrading

•

Improved regularity

•

Improved crush-resistance

•

Very well fitted for large water depths

•

Can be delivered in very long continuous lengths without factory splices. The world longest continuous umbilical of 35 km length has been supplied by Kvaerner to BP for their ETAP development (also with no splices in the electric cables)

•

No or limited use of fittings. If used, welded steel tube fittings are more reliable than those for hoses (swaging)

•

No separate armouring layers in case of bundle based umbilical configuration (avoids bird-caging, corrosion of armouring wires etc.)

•

Separate weight members may be designed into the cross-section to adjust installation parameters or stability

•

Standard installation vessels and equipment can be used.

The main disadvantages of ISU are similar to those described in the previous section 7.2. Steel Tube Umbilical.


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ANNEX 01 MANUFACTURER ADDRESS


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ABB NORSK KABEL AS Postboks 369, Kjerraten 16 N-3001 Drammen, Norway Tel : 47 32 80 90 00 Fax : 47 32 89 34 08

ALCATEL KABEL NORGE AS P.O. Box 130 Økern N-0509 Oslo, Norway Tel : 47 22 63 88 20 Fax : 47 22 63 73 09

DUNLOP COFLEXIP UMBILICALS LTD Walker Riverside, Nelson Rd, Walker, Newcastle upon Tyne Tyne and Wear NE6 3PL, UK Tel : 44 191 295 0303 Fax : 44 191 295 0842

COFLEXIP & SERVICES INC. 7660 Woodway, suite 390 HOUSTON, TEXAS 77063, U.S.A. Tel : (1 – 713) 789 85 40 Fax : (1 - 713) 789 73 67

KVAERNER OILFIELD PRODUCTS AS Enebakkveien 71 B P.O. Box 9357 Gønland N-0135 Oslo, Norway Tel : 47 22 66 69 00 Fax : 47 22 66 64 00


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NKT CABLES NKT Allé 1 DK-2605 Brøndby, Denmark Tel : 45 43 48 20 30 Fax : 45 43 43 38 65

OCEANEERING MULTIFLEX 38553 FM 1774 South New Line Magnoia, Texas 77355 P.O. Box 49, USA Tel : 1 281 356 8790 Fax : 1 281 356 8459


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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK SUBSEA CONTROL SYSTEMS


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TABLE OF CONTENTS 1

INTRODUCTION ............................................................................................................ 9

2

GLOSSARY OF TERMS .............................................................................................. 10

3

CODES, STANDARDS AND REGULATIONS ............................................................. 12

4

CONTROL SYSTEM TYPES........................................................................................ 14 4.1

DIRECT HYDRAULIC .................................................................................................. 14

4.2

PILOTED HYDRAULIC ................................................................................................ 16

4.3 (PILOTED) SEQUENCED HYDRAULIC .......................................................................... 17 4.3.1 Electro-Hydraulic.........................................................................................................18 4.3.2 Electro-Hydraulic Multiplexed .....................................................................................19 5

RELIABILITY AND REDUNDANCY............................................................................. 21 5.1

RELIABILITY ............................................................................................................. 21

5.2

REDUNDANCY .......................................................................................................... 23

6

OPEN/CLOSED HYDRAULIC SYSTEMS.................................................................... 24

7

SYSTEM ARCHITECTURE.......................................................................................... 26

8

9

7.1

GENERAL ................................................................................................................. 26

7.2 7.3

SUBSEA ................................................................................................................... 26 HYDRAULIC/ELECTRICAL DISTRIBUTION ..................................................................... 26

7.4

NUMBER OF SCM FUNCTIONS .................................................................................. 27

7.5

HYDRAULIC DISTRIBUTION ........................................................................................ 27

7.6 7.7

ELECTRICAL DISTRIBUTION ....................................................................................... 27 EARTHING ................................................................................................................ 28

SYSTEM OUTLINE ...................................................................................................... 29 8.1

GENERAL ................................................................................................................. 29

8.2

TOPSIDES ................................................................................................................ 29

8.3

UMBILICAL ............................................................................................................... 29

8.4

SUBSEA ................................................................................................................... 29

MASTER CONTROL STATION (MCS) ........................................................................ 32 9.1

INTRODUCTION ......................................................................................................... 32

9.2 COMPONENTS .......................................................................................................... 32 9.2.1 Computer ....................................................................................................................32 9.2.2 Cabinet........................................................................................................................33 9.2.3 Displays & Controls.....................................................................................................33 9.2.4 Printer..........................................................................................................................34 9.3 INTERFACES............................................................................................................. 35 9.3.1 Subsea Communication..............................................................................................35 9.3.2 Supervisory Control System Interface ........................................................................39


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9.4 EMERGENCY SHUTDOWN .......................................................................................... 40 9.4.1 General .......................................................................................................................40 9.4.2 Well ESD.....................................................................................................................40 9.4.3 Production/Water-Injection ESD.................................................................................40 9.4.4 Field ESD ....................................................................................................................40 9.4.5 Hydraulic Shutdown ....................................................................................................41 9.4.6 HIPPS .........................................................................................................................41 9.4.7 Workover ESD Radio Link ..........................................................................................41 9.4.8 HPU Interface .............................................................................................................42 9.4.9 EPU Interface..............................................................................................................43 9.5 SOFTWARE/OPERATING SYSTEM/DISPLAYS ............................................................... 43 9.5.1 Operating System .......................................................................................................43 9.5.2 Displays.......................................................................................................................44 9.5.3 Operator ......................................................................................................................44 9.5.4 Supervisor...................................................................................................................46 9.6

MAINTENANCE ......................................................................................................... 47

9.7 SYSTEM FUNCTIONS ................................................................................................. 47 9.7.1 Tree Valve Control ......................................................................................................47 9.7.2 Choke Control ............................................................................................................. 48 9.7.3 Subsea Sensor Monitoring/Fast Scan ........................................................................49 9.7.4 Interlocks.....................................................................................................................49 9.7.5 Alarm Annunciation.....................................................................................................50 9.7.6 Workover.....................................................................................................................50 9.7.7 ESD.............................................................................................................................50 9.7.8 Well Test Management...............................................................................................51 9.7.9 Hydrate Region Warning ............................................................................................52 9.7.10 Reports........................................................................................................................52 9.7.11 Trends/Historical Data reporting & Data Logging.......................................................52 9.7.12 Tag Numbering ...........................................................................................................53 9.7.13 Operator-Specific Requirements ................................................................................53 10 ELECTRICAL POWER UNIT (EPU)............................................................................. 54 10.1 GENERAL ................................................................................................................. 54 10.1.1 System Operation .......................................................................................................54 10.1.2 Physical Description....................................................................................................55 10.1.3 Power System Specification .......................................................................................55 10.2 COMPONENTS .......................................................................................................... 56 10.2.1 General .......................................................................................................................56 10.2.2 Main Circuit Breaker ...................................................................................................56 10.2.3 Power Transformer/Power Stage & Isolation .............................................................57 10.2.4 Output Circuit Breakers & Current Limiters ................................................................57 10.2.5 Line Insulation Monitor................................................................................................57 10.2.6 Controls & Displays.....................................................................................................57



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10.3 TESTING .................................................................................................................. 58 10.4 MAINTAINABILITY ...................................................................................................... 58 11 UN-INTERRUPTIBLE POWER SUPPLY (UPS)........................................................... 59 11.1 DESCRIPTION ........................................................................................................... 59 11.1.1 General .......................................................................................................................59 11.1.2 System Operation .......................................................................................................59 11.2 COMPONENTS .......................................................................................................... 59 11.3 TESTING .................................................................................................................. 60 12 HYDRAULIC POWER UNIT (HPU) .............................................................................. 61 12.1 INTRODUCTION ......................................................................................................... 61 12.2 HYDRAULIC SCHEMATIC ............................................................................................ 63 12.3 EQUIPMENT DESCRIPTION ........................................................................................ 64 12.3.1 Supply Tank ................................................................................................................64 12.3.2 Return Tank ................................................................................................................64 12.3.3 Low Pressure System.................................................................................................64 12.3.4 High Pressure System ................................................................................................65 12.3.5 Circulation/Transfer Pump System.............................................................................66 12.3.6 Bulk Fluid Storage.......................................................................................................66 12.3.7 Controls & Instrumentation .........................................................................................66 13 TOPSIDES UMBILICAL TERMINATION UNIT (TUTU) ............................................... 67 13.1 INTRODUCTION ......................................................................................................... 67 13.2 DESCRIPTION ........................................................................................................... 67 13.3 TERMINATION OF CHEMICAL HOSES .......................................................................... 68 14 UMBILICAL.................................................................................................................. 69 15 SUBSEA UMBILICAL TERMINATION UNIT (SUTU) .................................................. 69 15.1 DESCRIPTION & COMPONENTS.................................................................................. 69 16 WEAK LINK ................................................................................................................. 70 16.1 DESCRIPTION & COMPONENTS.................................................................................. 70 17 SUBSEA DISTRIBUTION UNIT (SDU) ........................................................................ 72 17.1 GENERAL ................................................................................................................. 72 17.2 CONSTRUCTION ....................................................................................................... 72 17.3 INTERFACE WITH UMBILICAL ...................................................................................... 72 17.4 INTERFACE WITH SCM.............................................................................................. 72 17.5 ELECTRICAL DISTRIBUTION ....................................................................................... 72 17.6 HYDRAULIC AND CHEMICAL DISTRIBUTION ................................................................. 73 17.7 ROV CONNECTION................................................................................................... 74 18 SUBSEA ACCUMULATOR MODULE (SAM) .............................................................. 75 18.1 INTRODUCTION ......................................................................................................... 75 18.2 DESCRIPTION ........................................................................................................... 75 18.3 COMPONENTS .......................................................................................................... 76



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19 INTERCONNECTIONS ................................................................................................ 78 19.1 INTRODUCTION ......................................................................................................... 78 19.2 FIXED STAB PLATE ................................................................................................... 78 19.3 ROV STAB PLATE .................................................................................................... 79 19.4 CLAMP HUBS ........................................................................................................... 79 19.5 ELECTRICAL JUMPERS .............................................................................................. 79 19.6 HYDRAULIC COUPLERS ............................................................................................. 81 19.7 FIBRE OPTIC JUMPERS ............................................................................................. 82 19.8 JUMPER DEPLOYMENT .............................................................................................. 83 19.9 JUMPER RETRIEVAL.................................................................................................. 84 20 SUBSEA CONTROL MODULE MOUNTING BASE (SCMMB) .................................... 85 20.1 GENERAL ................................................................................................................. 85 20.2 CONSTRUCTION ....................................................................................................... 85 20.3 INTERFACE WITH SCM.............................................................................................. 85 20.4 WORKOVER SYSTEM INTERFACE ............................................................................... 85 20.5 INTERFACE WITH TREE VALVES & SENSORS .............................................................. 86 20.6 DOCKING ALIGNMENT ............................................................................................... 86 20.7 LATCHING MECHANISM .............................................................................................. 86 21 SUBSEA CONTROL MODULE (SCM) ........................................................................ 87 21.1 GENERAL ................................................................................................................. 87 21.2 HOUSING ................................................................................................................. 87 21.3 MOUNTING BASE ...................................................................................................... 88 21.4 INTERFACES............................................................................................................. 88 21.5 CONNECTIONS ......................................................................................................... 88 21.6 HYDRAULIC SYSTEM ................................................................................................. 88 21.7 SYSTEM DESIGN ...................................................................................................... 89 21.8 ELECTRONICS .......................................................................................................... 90 21.9 CONSTRUCTION ....................................................................................................... 90 21.10 CORROSION PROTECTION ......................................................................................... 90 21.11 PRESSURE COMPENSATION ...................................................................................... 91 21.12 RETURN LINE COMPENSATION .................................................................................. 91



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22 SUBSEA TRANSDUCERS/SENSORS ........................................................................ 92 22.1 INTRODUCTION ......................................................................................................... 92 22.2 GENERAL ................................................................................................................. 92 22.3 CONSTRUCTION ....................................................................................................... 92 22.4 INTERFACE WITH DISPLAY/MONITORING SYSTEM ......................................................... 92 22.4.1 SCM ............................................................................................................................92 22.4.2 4-20mA system ...........................................................................................................93 22.4.3 Subsea connections....................................................................................................94 22.4.4 Electrical isolation .......................................................................................................95 22.4.5 RFI ..............................................................................................................................95 22.4.6 Calibration ...................................................................................................................95 22.5 TYPES OF SENSOR ................................................................................................... 95 22.5.1 Pressure (PT)..............................................................................................................96 22.5.2 Temperature (TT)........................................................................................................96 22.5.3 Combined Pressure/Temperature (PTT)....................................................................97 22.5.4 Choke Position (ZT)....................................................................................................97 22.5.5 Differential Pressure (DP)...........................................................................................98 22.5.6 Downhole Pressure/Temperature (DHPTT) ...............................................................98 22.5.7 Sand Detector .............................................................................................................99 22.5.8 Pig Detector ..............................................................................................................101 23 MATERIALS ...............................................................................................................102 23.1 MATERIALS USED ....................................................................................................102 23.2 COATING ................................................................................................................103 23.3 CATHODIC PROTECTION ..........................................................................................103 23.4 GALVANIC ACTION ...................................................................................................104 24 MARKINGS.................................................................................................................105 24.1 EQUIPMENT MARKING ..............................................................................................105 24.2 SUBSEA MARKING GENERAL ....................................................................................106 24.3 MARKING METHODS ................................................................................................107 25 QUALITY ....................................................................................................................108 25.1 INTRODUCTION ........................................................................................................108 25.2 QUALITY PLANNING .................................................................................................108 25.2.1 Project Quality Plan (Project Management Plan).....................................................108 25.2.2 Design Plan...............................................................................................................108 25.2.3 Inspection and Test Plan ..........................................................................................109 25.3 MANUFACTURE .......................................................................................................109 25.4 TESTING .................................................................................................................109 25.5 INSPECTION ............................................................................................................109 25.6 CONCLUSION ..........................................................................................................109



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26 RUNNING TOOLS ......................................................................................................110 26.1 REQUIREMENT ........................................................................................................110 26.2 MINIMUM FIT RUNNING TOOL (MFRT) ......................................................................110 26.3 MULTI MODE RUNNING TOOL (MMRT) .....................................................................110 26.4 SINGLE W IRE DEPLOYMENT. ....................................................................................111 26.5 DRILL STRING DEPLOYMENT ....................................................................................111 27 FACTORY ACCEPTANCE TESTING (FAT) ...............................................................112 27.1 GENERAL ................................................................................................................112 27.2 TEST REQUIREMENTS ..............................................................................................112 27.3 DOCUMENTATION ....................................................................................................113 27.4 TEST PARAMETERS .................................................................................................113 27.4.1 Master Control Station ..............................................................................................113 27.4.2 Electric Power Unit....................................................................................................114 27.4.3 Uninterruptible Power Supply ...................................................................................114 27.4.4 Hydraulic Power Unit ................................................................................................115 27.4.5 Subsea Control Module and Mounting Base............................................................115 27.4.6 Subsea Accumulator Module....................................................................................115 27.4.7 Subsea Distribution Unit ...........................................................................................115 27.4.8 Subsea Umbilical Termination Unit ..........................................................................116 27.4.9 Topsides Umbilical Termination Unit ........................................................................116 27.4.10 Transducers ..............................................................................................................116 27.4.11 Weak Link .................................................................................................................117 28 SYSTEM INTEGRATION TESTING (SIT) ...................................................................118 28.1 GENERAL ................................................................................................................118 28.2 TEST REQUIREMENTS ..............................................................................................119 28.3 DOCUMENTATION ....................................................................................................119 28.4 TEST PARAMETERS .................................................................................................120 28.5 POST-SIT CHECKS ..................................................................................................121 29 ALTERNATIVE CONTROL SYSTEMS .......................................................................122 29.1 INTRODUCTION ........................................................................................................122 29.2 BUOY BASED CONTROL SYSTEMS ............................................................................122 29.3 AUTONOMOUS SUBSEA SYSTEMS .............................................................................123 29.3.1 Introduction ...............................................................................................................123 29.3.2 Power Generation .....................................................................................................124 29.3.3 Subsea Control System ............................................................................................124 29.3.4 Hydro-Acoustic Telemetry System ...........................................................................125 29.3.5 HAPAC......................................................................................................................126 29.4 ALTERNATIVE TECHNOLOGY ....................................................................................127 29.4.1 Introduction ...............................................................................................................127 29.4.2 Fibre Optics...............................................................................................................127



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30 HIGH-INTEGRITY PRESSURE PROTECTION SYSTEMS (HIPPS) ...........................130 30.1 INTRODUCTION ........................................................................................................130 30.1.1 Requirements............................................................................................................131 30.1.2 Typical system ..........................................................................................................133 30.1.3 Pressure Transmitters ..............................................................................................133 30.1.4 Control Hardware......................................................................................................134 30.1.5 Barrier valves ............................................................................................................135 30.1.6 Surface Equipment ...................................................................................................135 30.2 SYSTEM TESTING ....................................................................................................136 30.3 OTHER CONCERNS ..................................................................................................136 30.4 SUMMARY ...............................................................................................................137 31 APPENDIX A - AUTHORS & VENDOR CONTACT DETAILS ....................................138 32 APPENDIX B - TYPICAL CONTROL SYSTEM DRAWINGS......................................140



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1


INTRODUCTION

A subsea well requires a Xmas tree at the wellhead, housing valves that control the flow of fluids from the well and chemical injection fluids to the well. These valves are operated by actuators, which themselves require a source of hydraulic pressure to operate. The primary objective of a subsea control system is to operate these hydraulic actuators which are attached to gate valves on a subsea Xmas tree. In its simplest form, such as for single wells, the actuator is connected directly via an umbilical hose core to a source of hydraulic fluid from the Topsides facility and is operated by supplying fluid to, or venting fluid from the actuator (see section 4.1) When a field development requires two or more wells, there may be a requirement for more complex control, such as subsea choking of wells, commingling into a flowline, and a more sophisticated control system type may be required. The various types of Control System are described in section 4. The surface location of the subsea wells and the number of wells often dictates the system architecture, and conversely if the control system architecture is studied at the conceptual phase in a development, the well location may be influenced by the control system capability. The time taken for a subsea valve to respond to a control signal from the Topsides facility ("valve response time") may not be important for a single low energy well, or conversely can be a safety critical item in emergency shutdown system applications (ESD systems), or a potential environmental hazard if a High Integrity Pipeline Protection System (HIPPS) is used to protect a pipeline which is not fully rated to the shut in pressure of a well. Data may also be required. This can be for reservoir management, well monitoring, flow assurance, or diagnostics. The means for provision of data may also dictate the control system type. As field development complexity increases and technology advances, the capability of control systems has had to improve from the original basic on/off control requirement. Depending on the development, there may be the need for such items as controlling subsea booster pumps or submersible lift pumps, subsea separator control, or multi-phase metering. Due to the changing technology, this list of possibilities is not exhaustive. This chapter is an introduction to the types of subsea control systems, their architecture, and some of the basic pointers for the selection of each type of system. The actual selection can only be made with knowledge of the full field architecture, the economics of the control system and umbilicals, and with consideration for all other costs such as platform or vessel access, and installation and hook up costs. All systems require a hydraulic supply for the actuation of hydraulic valves. A typical hydraulic power unit and its functions are described later in the text. A subsea control system consists of many component parts and therefore has many interfaces. A key component and critical interface is the umbilical itself, which is usually from a different supplier than the subsea control system. This section should be read in conjunction with the umbilical chapter. Offshore vessel time either during installation, hook-up and final commissioning, or later for field intervention is at a premium cost especially in remote locations where suitable vessels are not readily available. It is important therefore to focus on system detail and reliability including physical interfaces and material compatibility.



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2


GLOSSARY OF TERMS TITLE

DESCRIPTION

DHSV

Downhole Safety Valve

EDB

Electrical Distribution Box

E-H MUX

Electro-Hydraulic Multiplexed

EPU

Electrical Power Unit

ESD

Emergency Shutdown System

FAT

Factory Acceptance Test

FSK

Frequency-Shift Keying

HCR

High Collapse Resistant (Hose)

HDS

Historical Data System

HIPPS

High Integrity Pipeline Protection System

HPU


LVDT

Linear Variable Differential Transformer

MCS

Master Control Station

MFRT

Minimum Fit Running Tool

MIL-HDBK217(F)

USA –Department of Defence Military Handbook on the Reliability Prediction of Electronic Equipment

MMRT

Multimode Running Tool

Modem

Modulator/Demodulator

Multiplex

“of many parts” Data from many sources carried via a single communications link

NAS

National Aerospace Standard

Offset Distance

Distance of the control facility from the production well

P&ID

Process & Instrumentation Diagram

PETE

Portable Electrical Test Equipment

PETU

Portable Electrical Test Unit

POD


RVDT

Rotary Variable Differential Transformer

ROV

Remote Operated Vehicle

SAM

Subsea Accumulator Module

SAMMB

Subsea Accumulator Module Mounting Base

SCM


SCMMB

Subsea Control Module Mounting Base

SCP

Subsea Control Panel

SCSSV

Surface-Controlled Sub Surface Safety Valve

SDB

Subsea Distribution Box

SDU

Subsea Distribution Unit

SEM

Subsea Electronics Module

SIT

Site Integration Test

Subsea

The subsea equipment usually on the seabed, or mounted on equipment at the seabed



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TITLE

DESCRIPTION

DHSV

Downhole Safety Valve

EDB

Electrical Distribution Box

SUTU

Subsea Umbilical Termination Unit

TDU

Tool Deployment Unit (ROV)

Topsides

The surface mounted equipment, either on a platform, floating production facility such as an FPSO, or onshore land based

TUTU

Topsides Umbilical Termination Unit

UPS

Un-interruptible Power Supply

UTA

Umbilical Termination Assembly

HIPS

High Integrity Pressure Protection System

OPPS

Over Pressure Protection System (See HIPPS)



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3


CODES, STANDARDS AND REGULATIONS Reference

Title

AODC 035

Code of Practice for safe use of electricity underwater

API RP 17F /

Recommended Practice for the Design and Operation of Subsea Production Systems Part 6 “Design and Operation of Production Controls” - DRAFT

ISO-WD-13628-6 API 17H / ISO-WD-13628-8

Design and Operation of ROV Interfaces with Subsea Production Control Systems – DRAFT

API RP 14C

Recommended Practice for Analysis, Design, Installation and Testing of Basic Safety Systems on Offshore Production Platforms

API RP 17A

Recommended Practice for the Design and Operation of Subsea Production Systems Part 1 “General Requirements and Recommendations”

BS 3939

Graphic Symbols for Electrical Power, Telecommunications, and Electronic Diagrams

BS 2917 / ISO 1219

Graphical symbols used on diagrams for fluid power systems and components.

BS EN 55014

Radio Interference limits & Measurements for electrical appliances, portable tools & similar electrical apparatus.

IEC 60079-11

Electrical Apparatus for potentially Explosive Atmospheres

BS 6231

Specification for PVC Insulated Cables for Switchgear and Control Gear Wiring

BS 6360

Specification for Conductors in Insulated Cables and Cords

BS 6370

Code of Practice for Instrumentation in Process Control Systems: Installation, Design and Practice

BS 7671

Requirements for Electrical Installations, IEE Wiring Regulations 16th Edition

BS EN 60 068-2- Environmental Testing Procedures Test, Test “Ea” and Guidance – 27 Shock BS EN 60 068-2- Environmental Testing Procedures Test, Test “Ed” – Free Fall 32 BS EN 60 529

Specification of Degrees of Protection provided by enclosure (IP Code)

ISO 9000-3

Guidelines for the Application of ISO 9001 to the Development, Supply and Maintenance of Software

BS EN ISO 9001/ 9002 / 9003

Quality Systems



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EN 50081-1


Generic Emission Standards For:EN 55022 Class A Conducted RF emissions EN 55022 Class A Radiated RF emissions

EN 50082-1

Generic Immunity Standards for:IEC 801-2 Electrostatic Discharge IEC 801-3 Radiated RF Immunity IEC 801-4 Fast Transients common modes

Reference

Title

EN 50082-2

EMC Generic Immunity Standard for Industrial Environments

NAS 1638

National Aerospace Standard for hydraulic fluid cleanliness

DIN 50049.3.1(b)

Material Traceability Requirements



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4


CONTROL SYSTEM TYPES

There are five basic control system types: •

Direct Hydraulic

•

Piloted Hydraulic

•

(Piloted) Sequenced Hydraulic

•

Electro-Hydraulic

•

Electro-Hydraulic Multiplexed

All of these may be either open- or closed-loop in operation (see section 6)

4.1

Direct Hydraulic

A direct hydraulic system is the simplest type of subsea control system. The basic component for the control circuit for a direct hydraulic actuation of a subsea valve is a three-way handvalve mounted on a topside panel. The valve inlet is connected to the hydraulic supply. The return is connected to the reservoir, and the outlet connects to a hose in the control umbilical. The hose acts as a conduit that directs the hydraulic fluid to the subsea actuator. A pressure gauge on the topside panel at the three-way valve outlet gives an indication that the hand valve has been operated and hydraulic pressure is being supplied to the umbilical.

PI

PI

Umbilical Hose

Hydraulic Supply

3 Way Hand Valve Control Panel

Subsea Tree Valve

Figure 4.2 - Direct Hydraulic Control System There are two main limitations of this system, firstly response time and hence offset distance, and secondly lack of data for well monitoring or diagnostics. When the three-way valve is actuated, hydraulic fluid from the HPU will flow through the valve into the hose in the umbilical. The hose is full of hydraulic fluid at atmospheric pressure. To open the subsea valve it is necessary to fully pressurise the thermoplastic hose over its entire length which will expand by a nominal 10%, and to flow through the hose the total volume of the valve actuator. Opening the valve requires sufficient force to overcome the valve friction, the pressure in the valve bore, and to compress the return spring. Once the valve is open, it will remain open with very little hydraulic force. The hose expansion can be minimised by decreasing its bore size. However there is a tradeoff here in that the hose still has to flow the volume of the subsea actuator. With a small bore



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hose and a long offset, the internal friction in the hose makes flowing of hydraulic fluid very difficult to do, so larger bore hoses are necessary. As the offset distance increases, the valve response time increases. The acceptable response time depends on several factors:

•

The energy of the well and hence its flow through the closing valve, and

•

The position of any safety valves downstream of the closing valve.

An acceptable response time must be determined by hazard (HAZOP) and safety analysis. As an indication of the distances that can be controlled by direct hydraulic control using thermo-plastic hose, 4 km is probably the furthest that should be considered. For deep-water applications, the umbilical length from the surface to the seabed has to be included into the 4 km nominal length and therefore limitations of direct hydraulic systems become apparent. The expansion characteristics and the external crushing caused by the static head of seawater can be eliminated by using steel tube in the umbilical. There is one field in the Gulf of Mexico where an 11 km offset has been achieved using a steel tube umbilical in a directhydraulic system.

Figure 4.3 - Direct Hydraulic Control Panel The closure of a subsea valve is the reverse of opening. By operating the three way valve into the closed position, the umbilical core vents to atmospheric pressure in the hydraulic reservoir. The volume of the actuator and the expansion of the hose core have to be returned to the hydraulic reservoir in order for the valve to return to the closed position using the force of the return spring. In order to achieve the simplicity of the direct hydraulic system, there is one hose conduit for each hydraulic function, and there are no cables in the umbilical for data monitoring. It is possible to include twisted and screened signal pairs into an umbilical to access data from transducers using 4-20mA loops. This capability is dependent on the power drivers for the loops and the size of the conductors, and the offset distance. There needs to be a twisted and screened signal pair for each transducer. Another consideration in deep-water applications is that gate valve actuators may require larger springs to compensate for the pressure caused by the static head of seawater. The size of the spring usually requires a larger spring cartridge housing, and hence the valve actuator volume also increases, having detrimental effects on valve opening and closure response times.



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Control fluid pressures may be increased allowing the use of smaller actuators. Also, balanced stem actuators may be employed to reduce the resistance to motion from the hydrostatic pressure.

4.2

Piloted Hydraulic

The piloted hydraulic system is a variation to the direct hydraulic system, with slightly more complexity to overcome the limitations of the direct hydraulic system. The piloted system requires two hoses in order to function, and a piloted control valve subsea adjacent to the valve actuator. The objective of the system is that instead of the compromise choice of umbilical hose size for optimum performance using a direct hydraulic system, the piloted system uses a small bore hose for the pilot line and a larger bore hose for the supply line.

PI

PI

Hydraulic Supply

3 Way Hand Valve

Umbilical Pilot Hose 1/4"

P Umbilical Supply Hose 1/2"

Control Panel

Subsea Tree Valve

Figure 4.4 - Piloted Hydraulic Control System The objective is that the (preferably) large bore hose that is required to flow the volume of the actuator is continually pressurised from the hydraulic power unit. Therefore on valve actuation there is no delay whilst this hose is pressurised. The small pilot hose is operated using a three way panel mounted valve supplied from the hydraulic power unit in a similar manner to the direct hydraulic system. The difference between the systems is that although the hose will expand under pressurisation, the smaller hose requires less expansion. Secondly, the hydraulic pilot volume to actuate the pilot valve is very small and hence there is very little volume flow required to energise the pilot valve and to open the subsea valve. The result is that the valve actuation time is improved. The valve closure is the reverse procedure. When the three way valve in the control panel is moved into the closed position, the pilot line starts to depressurise into the hydraulic reservoir. The volume in the pilot hose is small, and the pilot return spring can be designed to snap action closed at a higher pressure than is possible from the valve actuator in the direct hydraulic system. The snap action closed of the pilot valve connects the subsea valve actuator to sea, and the return closed action of the subsea valve spring pushes the actuator volume to sea. As the subsea valve actuator volume does not have to flow along the length of the umbilical, valve closure time is also significantly reduced. For multiple subsea valve applications such as on a Xmas tree, there is a requirement for a pilot hose for each valve, but the larger supply hose can be used as a common supply feeder to all of the pilot functions.



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4.3


(Piloted) Sequenced Hydraulic

As its name suggests this system opens valves in a pre-determined sequence, depending on the magnitude of the pilot signal pressure from the Topsides control panel. Instead of a three way manual valve in the topsides control panel, there is a hydraulic regulating valve connected between the hydraulic supply and the umbilical hose to the subsea actuators, and the third port is a relief or vent back to the hydraulic reservoir. One of the benefits of this system is that it only requires one hydraulic (pilot) line. There is added complexity subsea in that each of the pilot valves for the subsea valves has a different spring rating. The system works by adjusting the regulator up to the opening pilot pressure of the first valve to open it. The response time to open the valve is similar to a direct hydraulic actuation. However for each subsequent valve actuation there is a small incremental adjustment (say, 500 psi) of the hydraulic pressure at the regulator and thus no noticeable further hose expansion.

P

1500 PSI

Hydraulic Supply

Vent PI

PI P

2000 PSI

Regulated Pilot Supply

HYDRAULIC SUPPLY

Regulator P

2500 PSI

Subsea Xmas Tree Valves

Control Panel P 3000 PSI

Sequenced Pilot Control Pod

Figure 4.5 - Sequenced Hydraulic Control System A typical system is shown in the diagram, with the first valve in the sequence opening at 1,500 psi (103.5 bar) and each subsequent valve opening at 500 psi (34.5 bar) pressure increments. In order to keep sufficient differential between valve actuations to prevent spurious opening, and to keep the system hydraulic working pressure within normal system design working pressures, the number of valve actuations in a sequence is limited. Closure of the valves is by reverse sequence where the valves close in sequence by reversing the system hydraulic pressure using the regulator. The two main advantages of this type of system are the improvement in response time and that theoretically, only one hose is required in the umbilical. A disadvantage is that a pressure regulator is required to operate the valves and these can be unreliable when operating against a closed system with no flow. A further disadvantage is that the valves can only be opened and closed in the same sequence. This may be acceptable for well opening and Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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closing for production requirements, but does not allow any flexibility for procedures such as well servicing or chemical injection batching. Also the basic system format is without remote sensing for data and diagnostics. A variation of this system exists in which an additional single supply line is used to supply the fluid that operates all the actuators, and the pilot line merely controls the sequence as described above. With this system, the pilot line can be of smaller diameter and the pressure variations due to the opening of the actuators no longer affect the pilot system.

4.3.1 Electro-Hydraulic The electro-hydraulic principle is similar to the piloted hydraulic system. The difference is that the pilot valve adjacent to the Xmas tree valve is replaced by a solenoid valve. The following figure shows the electro-hydraulic principle with an electrical switch in the topsides panel being made to energise the solenoid coil, which then energises the valve shuttle and connects the hydraulic supply through the umbilical to the valve actuator to open the valve. Closing is the reverse, by de-energising the solenoid the shuttle moves to the closed position by spring pressure and the supply is blocked and the actuator is connected to the vent for closure. Twisted Pair Cable Solenoid Valve

24v DC

S Hydraulic Supply

Umbilical Hose 1/2" Subsea Tree Valve

Figure 4.6 - Electro-Hydraulic Control System With the system as shown above, a cable pair has been introduced into the umbilical for one function only. Therefore for each additional function using this system another cable would be required in the umbilical. A standard solenoid has to be continually energised to stay open and to hold the subsea valve open. The solenoids may have a low power requirement, but voltage drops in the cable over long offset distances dictates a reasonable size cable conductor will be required. Also if further signal pairs are added to the configuration, the umbilical will grow in diameter adding to the cost and also making it more difficult to handle during manufacture and during load out and installation.



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4.3.2 Electro-Hydraulic Multiplexed The electro-hydraulic multiplexed system requires a step change in technology over the other systems. A single signal pair in the umbilical is used as a data highway for all of the valve commands and data requirements. To achieve this there is a requirement for a Subsea Electronics Module (SEM). The SEM is a vessel able to withstand external pressure and inside is a one atmosphere sealed nitrogen purged housing. Inside the SEM are the power supplies, step down transformers, ac to dc converters, modems, analogue boards to interface with internal and hydraulic remote sensors, driver boards for the solenoid valves, and some signal processing. The added complexity provides a great deal of flexibility and allows for monitoring of some of the circuitry to provide a health check on the system by providing data for housekeeping. As most modern systems contain microprocessors, there is scope for 'intelligent' handling of data and/or response to events such as high/low pressure alarms. As the system requires power, there is a requirement for a power supply through the umbilical. This can be provided by a separate power pair within the umbilical, or by what is termed "signal on power", where the signal is pulsed on the power pair which eliminates the requirement for the extra cable pair within the umbilical. The step-down transformer within the SEM allows the power within the umbilical to be transmitted at the optimum voltage for efficiency, which can then be stepped down within the SEM transformer to the voltages required for powering the electronics and energising the solenoid valve coils. Sometimes due to design reliability requirements, dual-redundant SEMs are specified. The solenoid valves are packaged into a housing along with the SEMs and integrated into what is called the Subsea Control Module (SCM). In order to communicate with the subsea control module, a modem is required topsides at the surface end of the communication pair. The interface between the Operator and the ESD system, etc is by a computer system commonly known as the Master Control Station (MCS) (described further in chapter 9).

Signal

PT TT

Power Hydraulic Supply

S

Transducers

FT

PT PT

Vent S

PT

Production Wing Valve

PT

Production Master Valve

S

Control Pod

Subsea Xmas Tree Valves

Annulus Master Valve

Figure 4.7 - Electro - Hydraulic Multiplex Control System



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The subsea power is provided via the Electrical Power Unit (EPU: described in chapter 10), and the hydraulic supply is from the Hydraulic Power Unit (HPU; see chapter 12), the same as for the other control system types. For deep-water applications where flow assurance and reservoir management are required, the electro-hydraulic control system provides benefits that the other systems cannot.



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5


RELIABILITY AND REDUNDANCY

5.1

Reliability

The remote location and the lack of (or expense of) access to any subsea equipment is a major consideration in system design. There are many components and interfaces on a subsea control system that can fail. There are many reasons for failure. The list below is indicative rather than all encompassing: Direct Failures:

Corrosion, joint failure, splice failure, sensor failure, solenoid valve failure, water creep, SEM failure (power supply, modem, solenoid driver, microprocessor, etc), hydraulic coupling leak, hose failure, weld failure, dynamic umbilical fatigue, electrical connection failure.

Indirect Failures:

Dropped object, umbilical dragged by anchor chain or trawl board, wax or hydrate blocking sensor port,

Reliability can be improved by proper burn-in of electronics, and testing, such as shock and vibration. Minor details such as hydraulic coupling seal compatibility should not be overlooked. Electronic components sourced by manufacturers can vary from full 'military' specification, through 'industrial' high or low grade to 'commercial' (household quality) with little visibility or control by the purchaser. The reliability of any single component that could fail and shut in a field should be questioned. If the component cannot be replaced with a better component, then there should be an alternative redundant path designed into the control system in case of component failure. Reliability analysis can be a complex task and setting specific reliability targets is often misleading and difficult to verify, requiring clear definition of the sub-systems and the failure modes to be included in the analysis, and the resulting reliability models. A reliability analysis is a statistic analysis of the probability of survival of the system, but it is important to recognise the mathematical basis to this analysis and the meaning of the terms employed, which are sometimes misconstrued to be some form of guarantee that the equipment will survive. For example, the probability of survival Ps of a system over a time it is defined as Ps(t) = e -Ȝt where Ȝ

= failure rate t

= time

Ps(t)

= Probability of survival i.e. reliability

As a corollary of the above: Pf(t) = 1 - e-Ȝt Where the parameter MTBF can be defined (for the exponential distribution) as that time at which 36.79% of a given population can be expected to survive, or, alternatively, an individual component has a 36.79% probability of surviving until that time.



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MTBF can be calculated as the reciprocal of failure rate (Ȝ) MTBF = 1/Ȝ Analysing the models requires the use of established databases, such as MIL-HDBK-217 to obtain the failure rate (Ȝ); these databases, however, are comprehensive for electronic components, but less useful for mechanical and hydraulic components, making a complete analysis difficult to quantify. Setting specific 'minimum component MTTFs ' is therefore impractical. A more realistic approach is to ensure all components used are to a suitably high specification, for example, electronic components used should be to at least 'industrial' grade, rather than 'commercial'. This latter grade, as well as assuring a higher QA level during manufacture, also sets the ambient temperature over which the device operates and a 'commercial' level component may well not be suitable for the temperatures experienced in a system, particularly during land-testing or even when operating inside an enclosure. In addition, the likely physical failure mode of a component or sub-system should be considered (if possible), to ensure the overall system fails in a 'safe' manner. A more useful figure is that of 'Availability' of the system, which is defined as: MTBF MTBF+MTTR where

MTBF = Mean time between failure MTTR = Mean time to repair

It can be seen from this equation that the shorter the MTTR, the better the overall availability of the system, and it is this parameter which is a far better target of attention during the system design (the value of MTBF is thus not quite so relevant, for example if MTBF is 1000 hours, a 1-hour MTTR gives an availability of 99.9% and an MTBF of 100 hours with the same MTTR gives 99.01%, whereas a 10-hour MTTR gives 99.00% and 90.9% respectively). It can be improved by arranging for a modular design, adequate tooling to facilitate retrieval and replacement, maintaining a reserve of spare modules etc. A mathematical (statistical) analysis can be employed to calculate the number of spares of any particular sub-element of the system , but in practice this is more influenced by commercial and contractual issues than an analysis, and it is more usual to choose a 'practical' level of spares or instigate a "TVM" (Total Vendor Management) style support contract (to avoid purchasing a large number of spares that may never be utilised).



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5.2


Redundancy

The usual method employed to improve the reliability figure is to duplicate those parts of the system considered to be at high risk - i.e. by adding 'redundancy'. Redundancy has to be considered in terms of complexity and cost. The implementation of dual systems improves the (mathematical) reliability but it should be noted that all systems must eventually be consolidated at some single physical point (e.g. at the Tree Valve actuator, or at a solenoid pilot valve in an SCM) and the failure mode of this consolidation point can sometimes degrades the overall integrity of the system, as in practice a failure at this point might prevent both dual-redundant paths from operating. (A reliability analysis often assumes this single mode has a zero failure rate). For example, a shuttle valve required for a dual hydraulic system can be stationary at one of its two positions and when called to activate due to a hose failure, the shuttle can jam in position or its o-ring seals can have set in their deformed position and moving the shuttle causes seal failure. The normal level of a dual redundant control system is as follows:

• • • • • • •

Dual MCS with cross-over Dual Channel EPU HPU with duty and standby pumps for LP and HP hydraulic systems Dual LP Hydraulic paths in the umbilical to the SCM Dual HP Hydraulic paths in the umbilical to the SCM Dual Signal Paths in the umbilical to the SCM Dual Power Paths in the umbilical to the SCM

Within the SCM:

• •

Dual Power Supplies Dual Modems

Some manufacturers supply dual electronics as standard to justify the standard of electronic components used. Some Operators require higher levels of redundancy. Items such as Dual SEMs are specified for deepwater, and Dual umbilicals are sometimes specified. The provision of total dual system redundancy, also brings corresponding system complexity and increased cost. However system consolidation must end in a single point somewhere, for example at a Xmas tree actuator. For multi-well systems single point failures in control systems should be eliminated, particularly for 'key' valves that can influence Production, such as Manifold Valves. Whilst the failure of one Well in a multi-well system could be acceptable in terms of loss of production, the inability to operate a Manifold Valve could prevent the whole field from producing. Such critical application valves are often operated by two separate Subsea Control Modules. Even adopting such a philosophy, the consolidation method must be examined to avoid common-mode failures. Diverse redundancy has been used in the past, for example an electro-hydraulic system with sequenced hydraulic backup, but these are much less common now that the use of subsea electronics has proven itself over the years.



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6


OPEN/CLOSED HYDRAULIC SYSTEMS

The terminology "open/closed hydraulic system" defines whether the used control fluid is dumped to sea locally or returned to the surface after valve actuation. A simple system such as a direct hydraulic system can be defined as a "closed" system, because after actuating the hand valve in the control panel, the control fluid flows along the umbilical hose into the subsea valve actuator to open it. On closure the reverse happens as when the actuating hand valve in the control panel is put into the closed position, the open actuator volume is forced by the valve return spring back along the supply umbilical hose to the HPU reservoir. The sequenced hydraulic system behaves in a similar manner to the direct hydraulic system, and is therefore also a "closed system". For a piloted hydraulic system the pilot line behaves in a similar manner to the direct hydraulic system on operating the pilot of the three way pilot valve. which in turn provides hydraulic fluid to the subsea valve actuator. However the benefit of the piloted hydraulic system is that the hydraulic supply hose to the umbilical is continually pressurised to avoid the delay in pressurising and venting the hose on valve actuation. When the pilot command is executed open, the pilot valve switches the hydraulic supply into the subsea valve actuator to open the subsea valve. When the pilot valve is actuated closed the pilot valve spindle blocks the hydraulic supply port and connects the actuator to sea. The subsea valve then forces the actuator volume to sea as it closes under the return spring energy. The venting of the actuator volume improves the valve response time by not having to return the actuator volume of fluid back up the umbilical. This dumping of fluid to sea local to the subsea valve actuator is what is defined as an "open hydraulic system" (or "open-loop"). An electro-hydraulic multiplexed system has its actuation solenoids in the SCM local to the subsea valves to be actuated. However uniquely, the electro-hydraulic multiplexed control system can be used either in an open or closed hydraulic system. Generally mineral oil based E-H Mux hydraulic systems return the spent fluid back along a return line in the umbilical to the tank, as it is not environmentally friendly to dump mineral oil to sea. This type of system is called a "closed" hydraulic system. "Water-Based" (water + additives) Electro-Hydraulic Multiplexed hydraulic systems which use totally biodegradable hydraulic fluid can dump the hydraulic fluid to sea locally at the SCM in the open hydraulic system mode. However water based hydraulic fluid is also used for closed hydraulic systems. The selection of an open or closed hydraulic system can be a user preference or an economic decision. The economics is a trade-off based on the volume of fluid to be used for valve actuation over the field life cycle, against the incremental umbilical cost due to the addition of a suitably sized return line in the umbilical. There is also an increasing tendency to minimise environmental pollution in seawater, albeit by using a fully biodegradable hydraulic fluid. Current legislation permits the use of these fluids (which contain biocides and lubricants) up to a certain tonnage per year (many fluids are graded Class E, allowing up to 1000 tonnes per year according to UK legislation "UK Notification Scheme for the Selection of Chemicals for Use Offshore, OCNS"), although future legislation changes may possibly further restrict their use. The density of control fluid is a consideration, particularly for deep water applications. Waterbased fluid has a specific gravity of > 1 whereas mineral oil has an SG of <1.



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Selection of the control fluid depends on a number of factors:

• • • •

System type (open or closed loop)

• • •

Provides acceptable lubrication.

• •

Acceptable toxicity level and/or permitted discharge quantities at Country of use.

•

Cost

Suitability for the required operating temperature & pressures. Adequate (low) viscosity at lowest expected ambient temperatures. Provides an acceptable level of protection against biological/fungal growth (may require initial system cleansing using proprietary sterilisation fluid.). Available at the required cleanliness level (typically NAS1638 Class 6) Fully compatible with the control system equipment and umbilicals (depends on selected equipment Suppliers having tested their equipment with it). Available at the required geographical location within acceptable delivery times and volumes.

A particular factor in the selection of fluid is that of the downhole temperature. Care must be taken to select a fluid suitable for the expected temperature. "Ordinary" water-based fluids have an upper temperature of typically 85 degree Centigrade and alternative formulations are available for higher temperatures to about 150 degrees.



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7


SYSTEM ARCHITECTURE

7.1

General

There are many considerations as to the selection of a control system type and of the system architecture. The options and ultimate choice and the recommendation of the system type can be a fundamental decision to an engineer with system experience, or a difficult task to an engineer with little or no system design, installation and commissioning experience. The actual surface location at the mud-line of the wells is the principle factor in determining the field architecture and hence the subsea control system architecture. •

Wells may be pre-drilled and suspended for later tie back, or a well may be drilled vertically as a satellite well for tie back at a long offset to an existing platform.

•

There may be a requirement for a long term production flowing test or extended well test requiring down-hole well data. If the well test was to prove additional reserves there could be the requirement to build in the flexibility to tie in a second well at some time in the future.

•

Another option is to drill a number of highly deviated wells in a cluster at the surface for tie back to a surface facility such as an FPSO.

•

A well could be drilled and completed in shallow water at a remote location requiring a simple control system design that can be maintained with low technical skills.

•

A well could be drilled and completed in deepwater requiring installation and hook up of the subsea control system by ROV, and with the requirement to control a smart completion.

•

The Topsides location may be a manned or unmanned Platform, or Floating Production, Storage & Offtake vessel (FPSO) or semi-sub.

The above are just a few of the scenarios for a subsea control system field development study. Each option requires a different solution.

7.2

Subsea

The subsea control equipment can be located on the Xmas Tree or other subsea structure that can be a manifold or template. For deepwater applications it is common for the SCM to be located on the Xmas tree for running and retrieval with the Xmas tree, or for running and retrieving on its own.

7.3

Hydraulic/Electrical Distribution

The common distribution method is via a single umbilical to a subsea distribution unit (SDU). From the SDU, the cable and hose jumpers distribute out to the SCMs. Where there are wells daisy-chained along a pipeline route, the feasibility is determined by the voltage drops between the modules and the range of input voltage that the SCM can work over. This can be overcome by including individual power cores within the umbilical for each SCM offset. This may also be a consideration for signal on power systems where the signal loss due to noise filters limits the number of modules on the power pair. For systems with discreet signal pairs the theoretical limitation to the number of SCMs on a signal pair is limited by the number of unique communications addresses in the system manufacturer capability. In practice it is limited by the system offset, noise on the signal line, and signal bounce or echo (cable impedance matching). Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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7.4


Number of SCM Functions

Most SCMs, in an effort to achieve standardisation, are designed with sufficient functions to control two wells. Where the SCM is located on the Xmas tree this is not really a consideration. However if modules are controlling template wells it is feasible. If modules are controlling off-manifold wells then the feasibility depends on the complexity of the system and the offset distance of the wells from the manifold.

7.5

Hydraulic Distribution

The hydraulic distribution depends on the number of valve functions, the actuator sizes, and the frequency of valve operation whilst operating the system. Stored hydraulic energy subsea in accumulator bottles (Subsea Accumulator Modules, SAM) is required to allow fast sequential opening of subsea valves without affecting the operation of other valves in the system. The accumulators are charged up by the hydraulic supply in the umbilical. In deepwater applications, the external static head of seawater necessitates that there is an increase over the pre-charge nitrogen pressure in lesser depths making the use of accumulator bottles in deepwater not very efficient. Hydraulic Intensifiers can be used to eliminate the use of a high pressure hose line in the umbilical. The intensifier is connected to the low-pressure (LP) hydraulic supply, which it boosts up to the higher hydraulic pressure, required for the SCSSV operation.

7.6

Electrical Distribution

For power distribution, electrical pin connectors are used to provide the best electrical efficiency over the distribution system. These can be two-pin connectors for a power pair, or four-pin for two power pairs. A four-pin connector may also be used for a power pair and signal pair configuration for redundancy purposes. In services such as terminating signal pairs, multi-pin connectors can be used. Where screened cables are used, it is common to use 3-pin connectors, the third pin being for the connection of the screen (it is important to maintain a correct screening philosophy throughout the system, to ensure adequate screening against electrical noise and to prevent the inadvertent formation of 'earth-loops', which generate more electrical noise. Similarly, a correct earthing philosophy for the electrical/electronic system must be maintained). The telemetry systems used by the various Control Systems Suppliers communications systems are currently unique to each vendor, and may, or may not, be constructed according to an international specification. Therefore with the increasing requirement to communicate and control down-hole monitoring equipment, down-hole pumps, smart wells, multi-phase meters, etc, it is essential that system architecture in terms of communications requirements, power requirements and interface requirements is properly considered at the appropriate time. System architecture in terms of reliability, power signal and hydraulic efficiency needs careful consideration. It is also important to consider the system hook up by ROV. In deepwater applications the deployment costs and the ROV time to hook up are principal considerations in the optimisation of subsea control system field architecture. Similarly, the connection systems themselves must be properly designed and tested for the application concerned.



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7.7


Earthing

Earthing continuity is an important consideration in ensuring that all metal component parts are bonded to the rest of the adjacent structure to ensure adequate 'cathodic protection'. For example, stabplate-mounted connectors and couplings should be strapped to the stabplate themselves and the SCM Mounting Base should be strapped to the Xmas Tree. Couplings on jumper hoses may require earth straps if there is any risk that they might be at some disconnected from their (cathodically protected) connection points.



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8


SYSTEM OUTLINE

8.1

General

A subsea control system can be divided into three main sections:

8.2

•

The permanently installed topsides equipment

•

The umbilical and its terminations

•

The permanently installed subsea equipment

Topsides

The topsides equipment has a Hydraulic Power Unit (HPU) for all systems. The electrohydraulic control system also has a Master Control Station (MCS), and an Electrical Power Unit (EPU).

8.3

Umbilical

The control umbilical interfaces with the topsides umbilical termination via the Topsides Umbilical Termination Unit (TUTU) and the Subsea Umbilical Termination Unit (SUTU) at the subsea termination. The various types of Umbilical required are discussed in the Umbilical Chapter of the Reference Book.

8.4

Subsea

The Subsea Distribution Unit (SDU) can also be directly attached to the umbilical, but is often a separate unit especially where an umbilical weak link is required. The SDU distributes the hydraulic supplies and electrical power and signals to each of the locations where there is a requirement for a subsea control module (SCM) Electrical and Hydraulic Jumpers connect the SUTU to the SDU (possibly via a weak-link), and the SDU to the Subsea Control Module Mounting Base (SCMMB). These can be diver or ROV installable. The Subsea Control Module Mounting Base (SCMMB), which is usually mounted onto the Xmas tree of the subsea well, is the interface with the subsea control module. The SCMMB connects the outputs from the SDU into the SCM, and the Xmas tree hydraulic functions and monitoring sensors into the SCM. For a diverless (deepwater) system, the SCMMB usually has upward facing hydraulic and electrical connections to mate with the downward connection of the SCM during installation. In a diver-assisted system, the SCMMB may merely act as a 'parking' position for diverinstalled stabplates and connectors. The Xmas tree valve actuators are usually connected to the SCMMB using stainless steel tubing. The sensors are usually flange mounted (via double block & bleed valves to allow removal) and secured to the Xmas tree by stud bolts and nuts. The sensors are connected to the SCMMB by jumper cables. Sensors may, however, be flush-mounted to limit hydrate blockage, in which case they cannot be mounted using double block and bleed valves; they therefore cannot be removed without depressurisation of the pipework on which they are mounted, and this will have Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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important consequences for repair/replacement, such as the need to stop production to change a faulty sensor. Excessive demand for hydraulic fluid whilst opening Xmas tree valves in a sequence can momentarily reduce the local system pressure and hence cause valves that are already open to fail closed. During hydraulic analysis if this is considered a problem a Subsea Accumulator module (SAM) will be installed on the hydraulic lines into the Subsea Control Module to prevent this occurrence



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DEEPWATER REFERENCE DEEPWATER REFERENCE BOOK

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TOPSIDES INTERFACE CONTROL/ESD

VDU

Modems

Computer A I/0 RACK

WEAK LINK ASSEMBLY

SCMMB SCM 1

Watchdog Computer B

VDU

UPS

Master Control Station (MCS)

SCMMB SCM 2

SCMMB SCM 3

TUTU

Umbilical

SDB

UTA

EPU

TOPSIDES POWER SUPPLIES HPU

JUMPERS

SCM 4 SCMMB

SCM 5 SCMMB

SCM 6 SCMMB

TOPSIDES AIR SUPPLIES Chemical Injection Skid

XMAS TREE FUNCTIONS

Figure 8.1 - Electro - Hydraulic Multiplex System Schematic


SUBSEA CONTROL SYSTEMS SUBSEA CONTROL SYSTEMSPage 31

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9


MASTER CONTROL STATION (MCS)

9.1

Introduction

Any electro-hydraulic multiplexed subsea control system requires a topsides unit to provide the necessary interface between the Operator and the subsea equipment. As the system operates using electronic messages between the surface and Subsea Control Modules (see also SCM Chapter 21), some form of communications sub-system is required to perform this function. In addition, an interface with the Topsides Operator and/or Topsides Supervisory Control System and ESD system will also be required. The Master Control Station is the generic name usually given to the suite of equipment that performs this function. It will usually comprise of one or more racks of computer and interface equipment, (located in an Equipment Room), and an Operator Console located in the Central Control Room. Power to the subsea system is provided by a separate unit, the Electrical Power Unit (EPU), which is described in its own section, chapter 10, but is sometimes incorporated within the MCS suite of cabinets.

9.2

Components

9.2.1 Computer The heart of the MCS is inevitably a computer, or more often two computers operating in a master-slave configuration in order to provide a high availability. The computers used were originally often a proprietary unit manufactured by the Supplier, however in recent years commercially available machines have been used as confidence in their reliability has improved. Nevertheless, the use of commercial PC-based computers is still mostly restricted to test equipment, or to proprietary industrialised-PC equipment. The advantage of using such equipment is evidently the availability of support software and corresponding economy of cost. The importance of regular data from the subsea system and the need for high availability of Emergency Shutdown capabilities, tends to dictate at least a dual-redundant system. With this, two computers are operated simultaneously, continually exchanging data such that, if one fails, the other can immediately take over without significant loss of data or (more importantly) without causing an unwanted interruption of production or inadvertent shutdowns. A ‘watchdog’ circuit monitors the correct operation of each computer and switches to the other if one fails; this is usually a sub-system using signals from both the hardware (power supplies, temperature sensors etc) and software (signals issued once per software loop) and can therefore be quite sophisticated. It must also allow manual selection of each computer for maintenance purposes but should also prevent a faulty MCS from gaining control of the system. Usually, a three-position keyswitch is provided with Computer ‘A’, ‘B’ and ‘auto’ positions.



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9.2.2 Cabinet The MCS computer and associated input/output circuitry and hardware are usually housed in a 2 or 3-bay standard rack. At least one of these bays is taken up with the input/output terminals (typically ‘KlipponTM’ terminals), which may incorporate zener∗-diode safety barriers where signals are connected to higher risk areas. The cabinets may also include a small VDU and keyboard, for maintenance purposes (which may also double as a standby control console). Fan assemblies provide localised forced-air cooling. The racks also contain the Watchdog circuit (for a dual-computer system) plus local controls. Some Suppliers also incorporate the subsea power supply (EPU) in these racks, particularly where their modular design allows stacking, and where only a small number is required for the size of Field concerned. It is usual to allow for a degree of expansion in the system, as the MCS computer and telecommunications system can usually operate a large number of wells, (albeit with a reduced field scan time). It is usually only necessary to add additional Power Supplies and modem units to expand the field (as far as the MCS is concerned, although there may be far greater impact elsewhere in the form of additional umbilicals, subsea jumpers etc), so the racking hardware usually has some spare slots available, concealed by blank panels. The design of the rack is also influenced by its installation location – if it must be mounted against a wall, then rear-access is not available and the racks must be designed for front access, usually involving swing-out card-frames, which makes the racks larger than otherwise required. Similarly, the method of access for all the cabling must be taken into account, as top-entry and bottom-entry cabinets affect the layout of the internal components.

9.2.3 Displays & Controls Display hardware at one time was restricted to mosaic type Mimic Panels with dedicated switches controlling each operation. Inevitably, with the advent and acceptance of computers, this has now become the ubiquitous VDU, usually mounted within a dedicated console framework as part of the Central Control Room suite. The keyboard may be a proprietary device dedicated to the type of computer and operating system used, but is, again, now more typically a standard PC keyboard and mouse/trackerball. As with the Computers themselves, dual-VDUs may be employed to improve availability. If Central Control Room space is limited, they may be reduced to one display only, automatically switching from primary to backup computer in the event of failure of the former, but in this case there is often a second smaller VDU doubling as a 'maintenance' VDU housed within the MCS cabinets themselves. This will usually give access to all the main Operator interfaces as well as any lower-level maintenance functions

∗ A semiconductor device that limits the energy that can be transferred from a Safe Area to a Hazardous Area even under fault conditions; a zener barrier does not itself make a circuit intrinsically safe, it merely protects the integrity of an Intrinsically Safe circuit in the event of a fault. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Figure 9.1 - Master Control Station

Figure 9.2 - Dual MCS A single VDU is also acceptable if there is also a data link to other Topsides computers, such as to the main SCADA/DCS, allowing subsea data to be displayed elsewhere and (often) control of the subsea system itself. A separate 'Status Panel' is sometimes incorporated into the Console or the MCS Rack itself, to provide hardware control of the Master/Slave Computers and house indicator lamps showing the status of the MCS (online/offline etc.). Hardware ESD buttons may also be incorporated.

9.2.4 Printer An MCS is usually provided with an Events/Reports Printer, usually a standard dot-matrix or Laser printer, which prints events, alarms, control actions etc in real-time, thus providing a hard copy of all actions and readings. The same printer can also double as a report printer; the format of the reports being as selected during the design stage but typically comprise a summary of alarms and events over the previous 24 hours. Care must be taken during system design to ensure this Printer does not print unnecessary fine detail, as there is a large amount of data within a typical system and the printouts can very soon become very copious, to the extent that they become ignored, or the paper runs out, or it becomes difficult to find the event which actually triggered other events. Defining the type of event to be printed, or ensuring that finer detail can be recalled if necessary, also requires careful system design. All data should be stored within a buffer in memory so that it is available for later printing if the printer is unavailable due to lack of paper, off-line etc. Other management utilities should be available to select the data required, clear a full buffer, stop un-required printouts etc.



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9.3


Interfaces

9.3.1

Subsea Communication

9.3.1.1 General The Subsea Control Modules communicate with the surface via electronic means. The method of communication must be considered as two parts: the carrier system and the protocol used. There are two ways to convey information from one place to another:

• •

analogue digital

9.3.1.2 Analogue 'Analogue' means to convey information such that the voltage or current is in direct proportion to the value of the signal - this is the method most frequently used to obtain information from, say, a sensor, typically using a "4 to 20mA" loop in which the value of the current varies between 4mA and 20mA according to 0% to 100% of the full-scale reading. However, one pair of wires is required per sensor. This is adequate where only one sensor is involved but for a complete subsea control system comprising perhaps 5 sensors per SCM and 20 SCMs, this is clearly impractical. In an analogue system, the carrier is the voltage or current in the wire and the value of that voltage or current conveys the information. 9.3.1.3 Digital A "Digital" system converts these analogue signals into digital form, i.e. a sequence of binary 'data bits' where, say, 0000 (0 in decimal) represents zero and 1111 (15 in decimal) represents full scale, so a 1-bit change would represent 100/16 = 6.25% of full-scale (say, 312.5 psi for a 5000 psi sensor). In practice, a better resolution is obtained using more bits (typically 12 to 16). In order to achieve even greater resolution from Downhole Pressure Gauges, often 20+ bits are used, but for the majority of ‘normal’ sensors 12 bits (range of 4096) suffices, as there is little point in obtaining a fine resolution if the accuracy of the gauge itself does not match. In addition, a digital interface allows instructions to be sent between the topsides and subsea systems, as well as data. A suitable 'protocol' must therefore be selected such that each unit 'knows' when the binary information is meant to be 'data' or 'instructions'. A very simple uplink protocol (SEM to MCS) could be: START BITS 0000

ADDRESS SENSOR 1 SENSOR 2 0001

0010

1100

SENSOR 3

CHECKSUM

1010

11001

In this protocol, the receiver sees the first 4 '0's and recognises it as the start of a message. The next 4 bits are an 'address' and if the receiver has the same address, it will continue to expect data for itself. The next three sets of information are readings from sensors 1, 2 and 3. The final bits are a 'checksum', which are calculated by the Transmitter and appended to the message. The Receiver also calculates what it expects the Checksum to be and if they agree, accepts the whole message. Once the Receiver has recognised a command intended for it, it will reply with the data requested, or with a message confirming the requested action. This latter Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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method is termed ‘check-before-operate’ and is used as a double-check that the SEM does not select and activate the wrong valve when commanded to open or close a valve (see SCM section 8 for more details of ‘check-before-operate’) So a typical downlink command (from MCS to SEM) and uplink response (SEM to MCS) might be as follows, where the shaded cells represent a long digital message, typically comprising: MCS COMMAND (Shaded block in 'MCS Command' table below) START BITS

ADDRESS

COMMAND

STOP BITS

CHECKSUM

0000

0001

0010

11

11001

SEM REPLY (Shaded block in 'SEM Reply' table below) START BITS

ADDRESS

COMMAND

STOP BITS

CHECKSUM

11

11001

ACKNOWLEDGE 0000

0001

0010

MCS Command (shaded block = digital message as above) Request Status

Operate

Operate Valve (Operate)

Valve (Check)

SEM Reply (shaded block = digital message as in second above) Status

Echo Valve Address

Confirm Operate

This is a very simple example and in practice, longer and more complex message strings are used, but the principle remains the same. The protocols are sometimes also designed to match the particular Subsea Control Module hardware design, and may allow further errorchecking, redundancy and sometimes error-correction. These protocols were developed over the years by each Supplier to suit its particular system or to meet a specified requirement.



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A typical message cycle for a whole field (of 3 SCMs in this example) might then be: MCS Command Request Status SCM 1

Request Status SCM 2

Request Status SCM 3

SEM Reply Status SCM 1

Status SCM 2

Status SCM 3

In practice, this ‘scanning’ for the parameters of a complete system can take a certain amount of time, as only one SEM can be addressed (and can reply) at a time. A typical scan of a 10well subsea system can take about two minutes, but this is very dependent on the Supplier’s telemetry system, protocol, number of SCMs involved etc, so this can only be a ‘rule of thumb’ This type of message exchange system is termed ‘half-duplex’, as an SEM only replies when it receives a message intended for it, and the MCS waits to receive a reply from subsea once it has sent a command, thus there is traffic on the telecommunications link in one direction only at any time. With modern telecommunications methods, full-duplex (i.e. traffic in both directions simultaneously) is perfectly possible but is not usual in subsea systems, as a typical subsea system is never required to operate at such a high speed, or do many things simultaneously. In practice, the Operator will perhaps operate one valve only, then wait for pressures and temperatures to stabilise before proceeding to perform the next valve operation. Similarly, high speed datalinks are also not usual for the same reason, and the above protocols typically operate at 1200 - 9600 bits per second, which is very slow by modern standards (a typical PC modem to the Internet can now operate at 56,000 bits per second, by way of comparison). Faster datalinks require more sophisticated circuitry and careful attention to cable technology, shielding, impedance matching etc, so are not really necessary unless the system is required to handle fast control loops or video data. In the former case, for, say, subsea pump control logic, it is not necessary (or desirable) to include the MCS in the control loop when the SEM itself is already a microprocessor and can therefore handle local subsea control. 9.3.1.4 Carrier for Digital Signals In a 'digital' system, therefore, the information is conveyed by binary data, a sequence of '1s' and '0s' that can be transported by a variety of electrical methods: The carrier is the electrical method used to convey the data. There are a number of ways of electrically conveying information, some of which are listed below: a) Direct current (dc) The digital information is carried as a voltage or current whose value varies from one fixed level to another depending on whether it is a '1' or a '0'. It is a 'baseband' system in which a single electrical pulse represents the '1' (and zero volts a '0') and is therefore fast but requires accurate transmission and reception electronics. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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This method is used in some systems, but consideration must be made for the length of the umbilical between the Transmitter and Receiver, as dc signals are easily attenuated by the cable, and 'cross-talk' between different cores in the same umbilical can cause reception problems. The shape of the digital pulses becomes altered by these umbilical characteristics, (as a square pulse actually requires a very wide bandwidth to be accurately transmitted) and there is then a limitation to the frequency (bit-rate) that can be achieved. It is often tempting to use this type of carrier when large diameter copper cores are already being used in the umbilical for other purposes (such as downhole pumps), but again, such equipment can cause severe interference (voltage spikes) on the cores and hence impair reception. b) Alternating Current (ac) systems. Alternating current systems are more prevalent, as various methods are available to carry the information to reduce the effects of noise. The most widely used method for subsea systems is 'Frequency Shift Keying' (FSK) in which the frequency of the carrier is altered between two different values to indicate a '1' or a '0'. This is not a baseband system as a number of cycles are required to transmit a '1' or a '0' but the detection and transmission equipment do not require such accurate operation. The information is transmitted using only two frequencies, chosen such that they are within the known passband of the umbilical and are therefore not attenuated too much (or at least the attenuation can be calculated). A further advantage of such an ac system was originally that it could be used in conjunction with 'Inductive Couplers', which would otherwise block dc signals. Other methods of encoding exist, such as Phase-Shift Keying, Quadrature-AmplitudeModulation, etc., but the goal is to transmit the digital stream of information between the MCS and SCM and vice-versa. The device which converts the digital signals into the form suitable for transmission along the umbilical wires is the Modem (Modulator-Demodulator) - such modems are used nowadays in PCs to connect across ordinary telephone lines to the Internet, or in Fax machines to send and receive faxes; the principle is the same. Some Suppliers of Subsea Systems do use commercially available modems/protocols, thereby reducing the costs. Modems are very sophisticated devices nowadays, with built-in error detection and correction, data-compression etc and their performance is reliable. However, being third-party devices, their operation is proprietary and suitable Test Equipment may not be available, or be expensive. The early subsea systems used “in-house” developed protocols, which were specifically designed to match the particular SEM hardware and to implement redundancy and error-checking. 9.3.1.5 System Design The communications sub-system and the design of the SCM itself are interdependent, the protocol being dictated by the system requirements of the SCM. It is not usually possible, therefore, to use, say, an MCS built by one supplier with an SCM supplied by another. At the very least, a 'Protocol Converter' would be required, but there are other consequences such as system timing, interpretation of data, built-in commands, sequences, SCM-initiation (software reloading) sequences etc which have to be included within the MCS software which make this virtually impossible to consider. A 'Standard' interface and system operation for MCS/SCM does not yet exist.



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9.3.1.6 Operator Interface The primary interface with the Operator is via a dedicated VDU (or shared VDU, if the MCS provides an interface to other Topsides Control/Monitoring equipment, such as SCADA or DCS). Information is usually presented graphically to the Operator in the form of 'pages' of mimicpanel-like displays, similar to the original design P&IDs. These pages are described in more detail in Para 9.5.3. An associated keyboard and/or controlling device such as mouse or Trackerball allows commands to be entered into the system. The MCS then processes the commands and issues instructions to the subsea system and/or receives subsea data as appropriate.

9.3.2 Supervisory Control System Interface The MCS will often incorporate an interface with other Topsides Computer equipment, typically a Supervisory Control and Data-Acquisition System (SCADA). The latter is usually a large and complex system, allowing control and monitoring of many Topsides functions from a variety of control points, including sometimes a shore-based location. There is evidently a strong inclination to eliminate the dedicated MCS from a system design and replace it by the SCADA itself, thus economising on the cost of the MCS equipment and software. In this case, the topside component of the Subsea Control System is reduced to the communications sub-system described above. However, this places a heavy responsibility on the SCADA Supplier to duplicate all the functions and displays of the MCS and of the Client's Procurement Engineer to obtain the necessary interface information from the Subsea Controls Supplier and also to ensure that the SCADA supplier understands and correctly incorporates all the necessary requirements. This is in practice, a very difficult task, as current SCADA suppliers are NOT suppliers of subsea systems. Moreover, differences in contract schedules means that the SCADA may not be available in time to perform FATs on the subsea system or even commissioning, and so the first time one unit meets the other is often offshore, a very undesirable situation. Similarly, the MCS itself may be an integral part of the functioning of a sub-unit, such as the HPU, and its absence during FAT of the HPU poses a serious problem. A preferable approach is to specify a digital interface between the MCS and SCADA. This can be a 'standard' interface, such as ModBus TM, which can be adapted to receive all subsea display parameters and (with some reservation) to issue subsea commands via the MCS. With this interface, the two contracts can be kept separate, and the subsea system proved to operate before connection to the SCADA. Moreover, the MCS still provides a control point for the subsea system in case of unavailability of the SCADA. The electrical interface itself is then a simple RS232 or RS422 type serial interface, which allows a bi-directional exchange of commands and data over a short distance, adequate for on-Platform distances.



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9.4


Emergency Shutdown

9.4.1 General A Subsea System requires a carefully designed Emergency Shutdown System (ESD). The telemetry sub-system described above can only 'talk' with one SCM at a time. Moreover, the SCM itself can only operate one valve at a time (see chapter on SCM, chapter 21). Therefore, in order to close all the Tree and Manifold Valves in a subsea system, a string of commands is required to be sent to each SCM in turn in a particular sequence. In addition, the performance of the particular subsea system itself and of the valves themselves, must be taken into account, such that any shutdown sequence operates in the fastest but safest manner possible, that failure of valves to close does not prevent the rest of the system from shutting down, and that any such failures are noted and taken care of by alternative means. It is not usual for SCMs to have ESD sequences 'built-in' to their hardware or software, as this would be relatively inflexible if changes were required. This would also be a separate 'area' in their system design which would not often be activated, and so would remain untested for long periods, with the attendant concern that they might not work when required. It is more usual that the MCS simply issues a sequence of commands as would be done individually for normal valve operations, hence the circuitry used is the same and no special test functions are required over and above those normally provided for normal operation (see SCM section 21).

9.4.2 Well ESD The VDU display pertaining to a particular Well will usually have an 'ESD' "button" (or ‘soft key’, or sequence of keyboard commands) associated with it. Operating this key/command will cause the MCS to send a sequence of 'close' commands to the particular SCM for that Well, which will in turn close each Tree Valve as instructed. Usually an option is presented to the Operator as to whether the system should close the Choke or not, as this can be a time-consuming operation.

9.4.3 Production/Water-Injection ESD Other types of ESD may also be specified, such as 'Production' ESD, in which only those Wells feeding into the Production Flowlines are closed, leaving others alone. Similarly, another ESD may only close all Water-Injection Wells.

9.4.4 Field ESD A single button (flap-protected if in hardware) will cause the MCS to issue close commands to all SCMs in the system. As there could be many of these in a Manifold/Template type of system, it is usual for the sequence to be chosen such that, say, all Production Wing Valves are commanded closed first, and once flow has stopped, all other valves can be closed in groups following a pre-determined sequence. However, a time-delay is sometimes built-in to allow the Operator to override the rest of the sequence, in case the Shutdown is no longer required. Evidently, some concern may be felt at the thought of interrupting a Field Shutdown. The ESD system design must be carefully constructed to optimise Production Requirements without compromising Safety. Usually, the highest level of Shutdown also vents the hydraulic supplies to the subsea system (see HPU section, chapter 30) so that a complete subsea shutdown is inevitable. An electronic sequence is often initiated in parallel with such a 'hydraulic' shutdown, so that the (e.g.) Tree Wing Valves are closed first, before all controlling pressure is lost. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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9.4.5 Hydraulic Shutdown The HPU itself can usually perform a hydraulic shutdown of the subsea system, as mentioned above. The MCS ESD design also should include a means to route (at least) a Field ESD signal directly to the HPU in case of failure or unavailability of the MCS. This is usually performed via hardware relay logic and is thus independent of software.

9.4.6 HIPPS A subsea control system MCS is not usually designed as a HIPPS system (High-Integrity Pressure-Protection System) as such a system must be: a) highly available, b) highly reliable, and be c) fast-acting. With suitable careful design of the subsea system and MCS software, an emulation of a HIPPS system can possibly be achieved, but the correct implementation of such a system is via dedicated equipment and/or dedicated software or hardware facilities within the SCM itself. The subsea valves themselves must also be quick-acting and reliable. See HIPPS Chapter 30.

9.4.7 Workover ESD Radio Link For the larger subsea fields, it is highly likely that Workover will be occurring on one of the wells around a manifold or template at any time, or at least fairly frequently. In this event, an ancillary system is sometime procured along with the subsea control system to provide a radio link between the Workover vessel and MCS. In the event an ESD button on the Workover Rig is pressed (say, if a large object is dropped overboard), a radio signal to the MCS initiates a shutdown of all the Wells in that area. The radio system itself can be fairly standard in nature, and usually incorporates voice links as well as datalinks, so as to provide extra communication between the CCR and the Workover Rig without tying up the use of one of the UHF channels (usually in short supply, particularly during commissioning) or the ‘Sailor’ VHF sets. A description of this equipment is outside the scope of this chapter, but the interface with the MCS itself is usually fairly simple, and comprises several digital signals: MCS to Rig

•

‘Enable’ Workover ESD capability

•

ESD Acknowledge

Rig to MCS

•

ESD signal

On the Rig, the interface with the Operator is usually several robust hand-held units that can be positioned at the drill floor, Supervisor’s Office, Bridge etc and contain a shrouded pushbutton. Provided the system is ‘enabled’ by the MCS (requires prior arrangement with the Platform OIM/MCS Supervisor), an indicator lamp indicates the system is ‘available’ (i.e. enabled and with radio telemetry operating) and if the button is pressed, a radio signal causes the MCS to shutdown the Field (or local Wells, as per the system design).



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The MCS then responds with an ‘acknowledge’ signal, which illuminates another lamp on the Rig handsets. A ‘Test’ mode is usually available whereby the whole link is tested as if in normal operation except that the MCS does not perform the shutdown.

PLATFORM MASTER TELEMETRY UNIT EQUIPMENT

TELEMETRY UNIT CH. "A"

PSU "A"

TELEMETRY UNIT

CH. "B"

Control Panel & Signal Inhibit

MODU REMOTE TELEMETRY UNIT EQUIPMENT

CH. "A"

CH. "B"

INTERFACE RELAY + IS BARRIERS

UPS BATTERIES

PSU "B"

MODU POWER HPU MODU CONTROL SYSTEM SUBSEA CONTROL SYSTEM

HPU ESD PANEL (x1)

SUBSEA CONTROL SYSTEM

HAZ. AREA ESD PANEL (x2)

ESD Radio Link From Production Facility To MODU

Figure 9.3 - ESD Radio Link Block Diagram

9.4.8 HPU Interface The MCS will also be connected to the other units of the subsea control system, in this case the HPU, which is always located remotely from the CCR, often on the Cellar Deck or other remote location. It will monitor all aspects of the HPU operation and display the status of the unit in mimic form on the VDU. In most cases, the MCS has some limited control of the HPU itself, to stop pumps (but not necessarily to start them), to switch between redundant channels and to perform an ESD by venting all subsea pressure. In some systems, the HPU will be controlled and monitored through the Platform DCS and ESD systems, and there is then no interface with the MCS. The interface in earlier systems is usually ‘discrete’ i.e. each sensor in the HPU is directly connected to a 4-20mA interface in the MCS. Modern systems use a telemetry system that reduces the number of cables required at the expense of added complexity (bearing in mind the usual need for Zone 0 or Zone 1 operation of the HPU). The HPU itself is a complex unit, and is often operated by a microprocessor system in modern units, although this is not essential (see HPU section, chapter 12). Some designs of system use the MCS in the control loop (i.e. when correct subsea pressure is reached, stop the pump) but this requires the MCS to devote a high priority to the HPU subsystem and also means the HPU is no longer a self-contained unit. Digital messages between the MCS and HPU usually conform to Industry Standard ModBusTM protocols.



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9.4.9 EPU Interface As the EPU (see chapter 10) is also a sub-assembly of the subsea control system, and is located remotely from the CCR (though usually in a nearby Equipment Room), the MCS usually has an interface with it to enable displays of key parameters and a degree of control over its operation. Monitored parameters usually include:

•

Input Voltage & Current (sometimes ‘frequency’)

•

Output Voltage and Current (each channel)

•

Line Insulation Monitoring and/or

•

Group Alarm

Control capability usually includes:

•

Remote on/off control

•

Trip Reset (except Line Insulation Monitor)

The signals between EPU and MCS are usually discrete; it is not usual for a digital telemetry interface to be used.

9.5

Software/Operating System/Displays

9.5.1 Operating System The Operating System of the MCS is to some extent independent of the Client's functional specification. It will need to be one suitable for the particular computer concerned; typical operating systems are Unix, DOS, or Windows (NT). The choice is usually that of the Supplier's, as it will have built up expertise using a particular Operating System over the years. The Application Software that runs under the operating System and which controls how the MCS performs and 'looks', is either a proprietary one designed by the Supplier or a commercially-available third-party Process Control programme, such as 'In-Touch TM. The benefit of using the Supplier's proprietary design is that he has complete control over how it operates and can easily and quickly adjust, tailor, or correct errors. Errors in a third-party programme are virtually impossible to have corrected until a new version is issued by the manufacturer; however, such software can present a sophisticated interface to the Operator and has the benefit of (usually) being widely used in Industry and the Operator can usually tailor it (or at least the display) to its own requirements. A typical display has a mimic diagram, valve status information, controls and data. It can be customised to meet the Client’s requirements and to match designs used elsewhere on the Platform, to ensure commonality of operation. Modern displays can be animated and use ‘hypertext’-style links to lead to further in-depth information about the system. In order to avoid the need to mobilise a Supplier representative for small, straightforward changes, the client should ensure at least several areas are available to him for his own use or modification: a) The Displays b) 'Help' systems c) ESD sequences d) Trends/Historical Data Reporting Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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9.5.2 Displays A well-designed display system will allow simple and rapid access to the main operating displays. Access to more specialised 'maintenance' functions is often also available via the main Operator VDU, but protected by a 'password' system to prevent unauthorised access. These will usually be at several levels of access:

•

Operator

•

Supervisor

•

Maintenance

9.5.3 Operator A variety of displays are available to operate the system, and may typically comprise:

•

Overview of Subsea System

•

Manifold Page

•

Individual Well pages

•

HPU and EPU control and display

•

ESD summary/control

•

SCM Monitoring/configuration

•

Trends/History

•

Well Test Control

However, the displays provided are system-specific and are usually carefully specified by the Customer to match its existing CCR displays, colour-conventions, method of operating valves etc. A display 'page' on the VDU will typically be segregated into specific areas, which remain in the same position on every page so that the Operator rapidly becomes familiar with the layout. Modern computer-graphics now allow considerable sophistication in the way information is presented and are often 'Windows TM - based' and considerable care must therefore be taken to avoid overloading the Operator with information or complexity of operation.



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The following information is typically included on each page:

Alarms/Events Page 1

NAME OF THE SUBSEA FIELD

31 December 1999 23:59:59

Mimic of Well (Tree, Manifold, Field)

System messages F1

F2 Help

O/view

F3

F4

Template

Wells

F5 ESD

F6 HPU

F7 EPU

F8 Well

F9 Alarms

Test

•

Current items in alarm (latest few values only)

•

Page Number

•

Date/Time

•

Identification of the Field and Page on Display

•

A Mimic of the item selected, e.g. Well, or Field, Manifold, HPU, EPU etc

•

System messages e.g. ESD in progress, Valve PM-1234 opening etc

•

'Soft key' quick access to other pages



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A typical ‘In-Touch' Individual Well page is as follows:

A typical Overview might be as follows:

and a manifold control page as follows:

9.5.4 Supervisor An Operator with Supervisor-level access rights will, in addition to the above functions, be allowed access to the following functions:

•

Changing Hi/Lo Alarm limits

•

Cancelling or Pausing an ESD sequence

•

Placing a Well into ‘Workover’ mode (see 9.7.6)



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9.6


Maintenance

An Operator with ‘Maintenance’ level access rights will, in addition to the above, have access to all aspects of the system software. This level of access requires detailed knowledge of the system and is normally only given to maintenance engineers and the Supplier’s representatives. Typical items that are available under this access level are:

9.7

•

Allocation of Subsea Electronic Module Addresses to individual Wells

•

Modification of ESD sequences

•

Altering ‘events’ i.e. conditions which trigger other actions, such as ESD.

•

Editing of displays/addition of new ones

•

Modification of ‘Help’ files

•

Modification of control loops for other related equipment (e.g. HPU control loops)

•

Direct maintenance of application software programmes and data files

•

Test utilities, such as disk de-fragmentation, system diagnostics, reloading of SEM software,

System Functions

This section describes some of the typical operating modes of the MCS in more detail.

9.7.1 Tree Valve Control In order to operate a subsea valve, it is usual for the system to operate in a ‘check-beforeoperate’ mode, in which several exchanges of messages take place between the MCS and SEM to ensure that the correct solenoid driver is selected before power is applied to it, thus ensuring the correct valve is actuated. This operation has to be transparent to the Operator, but is usually implemented thus: On selecting a valve to be operated (via the Tree Mimic or by typing the Tag Number), the MCS will send the ‘check’ subsea command and on satisfactory response will flash the selected valve display. The Operator then has a short time in which to confirm the operation by typing ‘Yes’ or pressing the appropriate button, upon which the ‘operate’ command will be sent. Whilst the subsea valve is in transit (opening or closing) the display continues to flash (usually in an appropriate colour combination) and on completion of its movement (say, 30 seconds later) will change to steady red (or green as appropriate). It should be noted here that the actual method of confirming the status of a subsea valve depends on the subsea hardware available. There may not be any Valve Position sensors on the valve itself and so the position of the valve can only be ‘inferred’ by virtue of the fact that the SCM has applied pressure to the valve actuator. During the 30 seconds or so of a valve’s movement, the MCS will usually continue to scan for subsea parameters relating to that valve, as some systems also infer valve status by monitoring the pressure-pulse applied to the actuator and integrate the curve to attempt to determine that the correct volume of fluid has flowed, thus improving the confidence that the valve has not simply stuck. Scanning of other parameters is therefore slowed down during valve operations, although a slower scan rate may still be achieved by interlacing requests for other key parameters or data from other SCMs. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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9.7.2 Choke Control The method of operating a choke depends on its mechanical nature and the nature of its position sensor (see ‘Transducers’ section 22) The most usual type of choke is the ‘stepper’ type, which requires a pulse of pressure to an ‘open’ or ‘close’ piston, which in turn operates a ratchet & pawl to move the choke trim. In this case, the SCM design to operate it is similar to that for other tree valves. This method of operation is very precise, as one ‘step’ moves the choke trim by a fixed amount; usually some 70-120 steps are required to move from fully closed to fully open. Other types of choke mechanism do exist, notably the hydraulic motor type which require a continuous supply of hydraulic fluid to operate a hydraulic motor, and precise position control is less easy as there is always a time delay between reaching the desired position and shutting of the supply of fluid. A choke position sensor is ‘optional’ for the former mechanism but essential for the latter. These are usually Potentiometers, LVDTs or magnetically-coupled devices on the choke actuator, but as far as the MCS is concerned, it receives a digital value from the SEM indicating position. The Operator inputs a desired position of the choke (say, 60% open, or ‘bean-size’ in 1/64ths) and the MCS then computes the number of pulses required to reach that position and instructs the SEM accordingly. Often, a ‘single-step’ command is also available, for fine control. The choke control algorithm must be designed to accommodate a number of situations, such as failure of the choke to move (to avoid delaying the rest of the MCS software) or inaccuracy in the computed or measured choke position. It is preferable that the computed position and the measured position are not coupled (closed-loop operation), to avoid ‘hunting’ for an unreachable position, particularly when the choke sensor has an inherent hysteresis in excess of +/- ½ step, which is often the case. An ‘open-loop’ algorithm simply moves the choke the required number of pulses (steps) then stops, leaving the Operator to compare the displayed computed and measured positions. The algorithm also has to take into account the physical nature of the choke itself, in which the trim remains closed until after a number of ‘open’ pulses and also becomes ‘fully-open’ before the physical final stop is encountered, i.e.: Number of Steps from ‘fully-closed’ to ‘fully-open’ 0

15

16

96

120

0% Choke Open 100% It can be seen from the above that allowing a ‘closed-loop’ operation whereby the MCS continues pulsing the choke until the measured position corresponds with the desired position could lead to uncertain operation at the extremes of choke travel. Similarly, if the choke sensor fails, operation of the choke is then impossible and the system still then has to resort to ‘open-loop’ if any form of control is to be achieved. Sometimes the MCS is required to display ‘Flowrate’, as calculated from the differential pressure across the choke and the choke position. This is a reasonably straightforward calculation for fluids such as water, but gas flow is more complicated. In any event, the software requires calibrations coefficients for the particular choke concerned, in order to apply the necessary polynomial equations. The MCS must therefore store the coefficients for each choke, as supplied by the manufacturer, for use in the equations. Access to these is via ‘Maintenance’ level.



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9.7.3 Subsea Sensor Monitoring/Fast Scan The majority of subsea sensors in a typical subsea system are Pressure and Temperature, as measured by external subsea sensors, which are then connected to the SCM. Other types of sensor include Sand Detectors, Pig Detectors, Choke Position and Downhole Pressure & Temperature. Other sensors within the SCM itself measure the status of the subsea control system hydraulic supplies and status of the electrical systems. In all cases, these result in digital data being made available to the MCS in the uplink datastream. As stated previously, each sensor is accessed via a ‘status’ request command from the MCS, and therefore it can take some time to access all the sensors in the system. Usually, this is not a problem as a field can usually be ‘scanned’ in 2-3 minutes, which is adequate for normal operations. Sometimes, however, faster data rates are required, such as during valve movements when attempting to plot the pressure/time curve of the hydraulic supply to the valve, or for Well Test operations (see Para 9.7.8) where the Reservoir Engineer is interested in pressure transients just after closing or opening a valve. If the telemetry system exhibits the scan times mentioned above, it is usually necessary to implement a special ‘fast-scan’ mode for particular sensors, to ensure their data is accessed more frequently, say, once per second (sometimes faster). A special mode is usually available for this where one or more sensors can be put into ‘fast-scan’ mode, which ensures they are accessed more frequently, interposed with normal system scanning requirements. If the subsea system design cannot offer this, then sometimes the SEM is designed to store a block of ‘fast-scan’ data in memory, for later transmission to the MCS. Careful system design must ensure that this does not prevent normal operation of the system, or overuse of available memory, disk space etc.

9.7.4 Interlocks In principle, the Operator is allowed to operate any valve he wishes. However, many Clients ask for a degree of protection against inadvertent operations, by implementing various ‘interlocks’ within the MCS software. Providing a certain condition can be uniquely and precisely defined, the software can then check to ensure no other action is allowed whilst that condition persists, or can only allow an action if a precise set of conditions is met. For example, an interlock may be set up to prevent an Annulus Crossover valve being opened if the Annulus Master is open. The interlock may merely take the form of an interrogatory question, such as “Annulus Master is open – Continue Yes/No?” to which the Operator can answer ‘Yes’ if required and the action will then be allowed. The interlock may be a higher level one, whereby only the Supervisor can bypass it, such as opening the Downhole Safety Valve when other Production Valves are open, risking wear on the DHSV. In an ESD sequence, the Operator is often given the choice whether to close the choke(s) or not (as these are usually closed at the end of the sequence, when all other valves are shut therefore there is no production flow; shutting the choke merely ‘tidies up’ the system in preparation for restarting the wells later, but this operation usually takes a long time and can therefore be avoided if desired).



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9.7.5 Alarm Annunciation All MCS designs offer the expected alarm treatment of sensor readings, viz. HiHi, Hi, Lo, LoLo alarms, each of which limits can be individually set by the Supervisor. Usually, a reading in alarm will cause a flashing symbol on the VDU, plus an audible or Group alarm, a printout on the system printer and a record in the Historical Data Log within the MCS (see Para 9.7.11). The Operator can always cancel the audible alarm, which stops the symbol flashing, but the alarm remains displayed until the alarm condition clears. Usually, the latest alarms are shown in a fixed screen area on every page. A detailed table of current alarms is available on a dedicated display page, showing current accepted/unaccepted alarms and indicating whether they are Hi/Lo etc by use of colour or the appropriate symbol (H, L etc). Once an alarm is accepted and subsequently returns to normal, it is removed from this dedicated page, but a record of its occurrence will be available on the Printer printout and within the Historical Data system.

9.7.6 Workover The hardware design of the subsea equipment usually allows access by a Workover system, which can take direct hydraulic control of an individual Well from the Workover Vessel. This is usually by disconnecting the hydraulic outputs of the SCM from where they connect to the Tree. This means that the SCM can still operate a hydraulic output, but it will have no effect, and as Tree Valve status is usually ‘inferred’ (see 9.7.1), the MCS cannot inherently know that the valve has not operated. For this reason, Workover operations must always involve the Platform Operators, who, upon receiving advice that a well is to be put on Workover, will input this into the MCS after closing all the Tree valves, which in turn will usually ‘grey out’ the Tree valves for that Well and also prevent the Operator from trying to operate that Well. In practice, the Tree valves will be shut when Workover operations have finished, so the display will revert to ‘all closed’ on removing the ‘Workover’ mode. Closing the valves before Workover operations start ensures their status is known, and also that the SCM does not keep pressure on the individual control lines, which would cause the valves to open when the SCM output is reconnected to the Tree.

9.7.7 ESD The ESD system of a subsea field can be quite complex, due to the number of different modes of shutdown required, such as:

•

Platform Shutdown

•

Field Shutdown

•

Manifold Shutdown

•

Individual Well Shutdowns

•

Workover Rig ESD Transceiver Shutdown

The operation of each of these will be defined in an ‘ESD Cause and Effects’ Chart at the design phase and available in the system operating manual. Certain ESDs will be activated by incoming contacts from the Platform’s ESD system; others will be initiated by the MCS itself, either via an Operator command or in response to out-oflimit parameters.



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Each requires subsea commands to be sent to the subsea Tree Valves in a particular sequence (to ensure the correct cessation of flow in the most timely and system-friendly manner). The sequences themselves can sometimes involve time delays, or allow operator-intervention at particular points (and proceeding if none received within a certain time). Many sequences allow the Operator to choose whether to close the Choke or not (as this is usually a time consuming operation). A well-designed MCS system will allow access via ergonomic editor software such that the sequences can be modified if necessary or time-delays changed, etc. A typical simple shutdown sequence could be:

•

Close all Production Wing Valves (this will stop production flow)

•

Close all Production Master Valves

•

Close all Annulus Valves

•

Close Downhole Safety Valves (Operator choice)

•

Close all Chokes (Operator choice)

The software also must take into account the desired action, should any of the issued commands fail to operate (usually, this will be to initiate a hydraulic shutdown via the HPU) and must also take into account a system in which not all the Wells are yet installed. Different sequences will be required for Water-Injection Wells, and for Production Wells that must have Chemical Injection before fully closing them down.

9.7.8 Well Test Management Reservoir management usually requires various forms of Well test procedures to be carried out, usually routing product into a Test Separator, and monitoring subsea pressures immediately after closing or opening Production valves (well shut-in, well start up tests) from which Reservoir Engineers can deduce the characteristics of the reservoir. To achieve this, a sequence of valve operations plus associated ‘fast-scanning’ of various pressures and temperatures is usually required. This can be a manual operation performed by the Operators, or if the sequences or necessary control actions are too complex, can be automated, such that the operator merely has to select, say, “Well Shut-in test, Well 1”, and all the necessary valve commands and fast-scan actions are carried out automatically Usually, the resulting data will be made available to third-party analysis software, by means of downloading the data onto floppy-disc or data-cassette, in an established/agreed format. In some systems, a separate Test Flowline exists and by operating the required valves, flow can be routed from one particular well into the Test Separator. Again, this action can be made automatic if required, although Operators usually prefer to perform the operations themselves. The software can be made to ‘detect' if a well is placed on test, and a warning indication set on the relevant VDU screen(s). In this case, an incoming “Test Separator ESD” signal is then ‘routed’ such that only the particular well on test is shutdown, rather than all other producing wells.



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9.7.9 Hydrate Region Warning Certain Fields contain the type of crude which has a tendency to form hydrates at particular temperatures & pressures, and the Operators must always be vigilant that these are avoided, or are at least prepared for the eventuality by previously injecting chemicals. The MCS can be programmed to continually monitor the pressure and temperature of the crude, and activate an alarm if the values fall within the hydrate envelope. In principle, the MCS could also be programmed to perform valve operations on activation of this alarm, such as to inject chemicals or to alter choke positions to bring the pressure out of the hydrate region, but it is more usual that these actions are left to the Operators to perform.

9.7.10 Reports An MCS is usually equipped with a variety of pre-defined Reports, which can be selected by the Operator as required, or can be made to print automatically, say, every 24 hours. Ideally, the MCS should be equipped with Operator-definable Reports, in which the Operator can select the parameters to be printed, perform operators on them (such as ‘total’) and design the format, but this does require quite a sophisticated editing program. Alternatively, selected data can usually be output from the Historical Data System (see 9.7.11) onto a floppy disc or similar, for later processing via third-party software. Usually the regular ‘Daily Reports’ are produced by the higher-level Platform SCADA system, which has access to topsides production and export data, so Reports from an MCS are not used very often.

9.7.11 Trends/Historical Data reporting & Data Logging Being a computerised system, an MCS is able to store all the data received from subsea, plus any ‘events’ (such as alarms or Operator commands) on its hard disk drive. Most MCS software, whether third-party or in-house design, provide some form of graphical data-retrieval system that enables the operator to view previous data, usually in the form of a chart-display over the period selected. Display space limitations usually restrict the number of parameters that can be viewed at the same time to around 3-6. Selecting more parameters for display can often occupy the MCS processor and disc system to excessive tasking and can slow other operations. A typical graphical display of historical information is as follows:

The Operator can select the start and stop date and time for the selected parameter – the MCS will then retrieve the data from its hard disc and display it graphically, or a tabular display is often available. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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There are physical limitations to the amount of data that can be stored by any system, and certain compromises may have to be accepted at the design phase in order to optimise the system design between a practicable system capacity and the Clients’ requirements for data storage. In practice, an Operator is likely to need very detailed information stored for a short time (e.g. when performing Well Tests) but less detailed information for long-term storage. It is also very useful to be able to refer back over several months of data to find out, say, when a sensor failed (and try to relate it to some other event such as Workover at the time), or what caused a pressure to rise etc, in which case all ‘relevant’ events, such as Operator actions, need to be retained, but ‘irrelevant’ event, such as those inevitably resulting from major event, are candidates for being removed from the database (e.g. hundreds of alarms can result from the one major event of switching off the EPU). It is not particularly easy to adequately define such an ‘alarm hierarchy’ and the storage limitations of the MCS mean that printouts or data-storage of the database must be performed sooner rather than later when an event needs to be analysed. The same system may be used to display the value of selected parameters in ‘real-time’, thus providing ‘Trend’ information.

9.7.12 Tag Numbering Any subsea development will use a system of Tag Numbering, developed by the Client or its major contractor, which is used throughout the Platform and subsea system as a standard nomenclature for defining valves and sensors. Very often, a contract is placed for the subsea control system before this standard Nomenclature system is in place, and the system begins design using the Supplier’s own nomenclature, or internal computer reference numbers for each data point. The Tag Numbers then have to be retrospectively modified by the controls Supplier, which is not always a simple task, as it may involve a complete rebuild of the MCS database, and the Supplier will usually claim a Variation for this work. A preferable solution is the ability of the MCS to use client-definable/re-definable Tag Numbers via a relational database lookup system, such that arbitrary numbers can be used to begin with, then easily replaced with the final versions, the MCS ensuring that all occurrences of that Tag Number being automatically updated to reflect, display, and respond to, the new value.

9.7.13 Operator-Specific Requirements The MCS is sometimes configured to provide for operator-specific requirements, such as downhole data-logging and pseudo-leak detection. Downhole data-logging Reservoir engineers may wish to analyse downhole pressure and temperature data, particularly during shutdowns. Data logging to disk may be initiated manually or automatically, sampling rates may also be set manually or automatically to suit the particular application. Pseudo-leak detection Pressure-sensors can be selected from which rate of change of pressure derivatives can be set to initiate shut-in of wells when a set-point is exceeded.



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10 ELECTRICAL POWER UNIT (EPU) 10.1 General Any electro-hydraulic multiplexed subsea control system requires a topsides unit to control and provide the necessary power to the subsea equipment. (see section 9.1) The Electric Power Unit (EPU) is the generic name usually given to the suite of equipment that performs this function. It will usually comprise of one or more racks of equipment, located in an Equipment Room. The EPU is sometimes incorporated within the MCS suite of cabinets (see MCS section 9)

10.1.1 System Operation A subsea system will usually require power in a form different to that normally available on the Platform/FPSO. This is because of several reasons:

•

Early systems used ‘inductive couplers’ which require high(er) frequency power for efficient power transfer, typically 400Hz (being typically based on aviation technology).

•

Even after conductive connectors began to be more widely used, Suppliers still kept their existing designs of power supplies. Even where a normal 50/60Hz supply is required, the supply voltage may require stepping-up to a higher level in order to supply the distant subsea field, to reduce the I2R losses in the umbilical cable. Some supplier’s systems use direct current (dc) for power transmission, again at high voltages to reduce cable losses. Most subsea systems require dual-channel power for redundancy reasons. Some systems communicate subsea by superimposing signals onto the power supply.

• • • •

In addition to conditioning the available topsides power into the form required for transmission subsea, certain other control and monitoring is required, such as:

• • • • • • • •

Overall on/off control of the power to the EPU and to the subsea system itself. Individual control of each power channel. Protection for over-current and over-voltage. Monitoring of the supply voltage, current and frequency. Monitoring of the quality of the insulation of the subsea umbilicals. Replication of the measured parameters back to the Master Control Station (MCS). Adjustment of the output voltages when more Subsea Control Modules (SCM) are added to the system. A degree of regulation (stabilising, smoothing) of the incoming supply may be required.

All of these requirements usually mean that an EPU becomes a self-contained unit, and is of an appreciable size, weight and complexity. It should be noted that, regardless of the type of power required by the subsea system, a reliable supply is always required. This means that the system should ideally be supplied from the Topsides Uninterruptible Power Supply system. In the absence of this, or where the existing supply is inadequate, a separate UPS is often required. This is described separately in section 17, as it does not usually form part of the EPU, due to its specialised nature and size. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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10.1.2 Physical Description Modularisation of the unit by the Supplier may mean that one or more EPUs are required to power a large field, and the racking system usually contains space for such expansion. Sometimes the EPU requirements are small enough to allow the EPU to be mounted in the same Rack as the MCS. In general, an EPU will be designed to fit in a standard 19" rack and be protected against dust and water ingress to at least IP55. An EPU will often contain large and heavy transformers, so although the control and monitoring circuitry is relatively small, an EPU is usually fairly large and heavy. The EPU will often generate an appreciable amount of heat, and this should be taken into account when siting the unit and/or designing the local HVAC system. The racking system will be equipped with Certified lifting pad-eyes, gland plates (provided on the top or bottom of the unit) to accept glanded incoming and outgoing cables and "Klippon" SAK-type connectors, or similar, as terminations for all incoming and outgoing cabling. The enclosure should have two non-ferrous earth studs for bonding to the earth system. All enclosure metal parts should be securely connected back to the earth studs by bonding straps. An earth-bonding strap is required. The enclosure shall be suitably coated and painted in accordance with a suitable specification.

Figure 10.1 - Typical EPU

10.1.3 Power System Specification In order to specify the EPU requirements, each subsea system must be analysed for its current and future power requirements. The power distribution system can be quite complex, particularly for 'multi-drop' systems, i.e. those having many Subsea Control Modules operating from a single (dual-channel) umbilical and with, in some cases, further umbilicals operating in a daisy-chain to another field or collection of Subsea Control Modules. The system may require subsea Transformers, usually located in the Subsea Distribution Units (SDU; see chapter 17) to transform the voltage back down again to a level suitable for the SCMs or for local distribution on a template. An SCM will contain its own Power Supply system to obtain the (typically) 24 volts to operate sensors and solenoids, and 5 or 12-volt logic circuits. The system must be designed to accommodate the various levels of power required by the system in all its operating modes. An SCM in its normal operating (scanning) mode may only consume some tens of watts, but when a solenoid is activated this will rise by about the same amount. Some system designs incorporate 'held-on' solenoids in the SCM, and this increases Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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the total power requirements, as does each additional external sensor. Systems employing major power-consumers such as downhole pumps obviously have very particular requirements. The EPU is usually required to be able to adjust the subsea supply voltage to cater for the addition or removal of SCMs. The system must also accommodate any expected fluctuations from the Platform Supply; therefore the subsea system is usually fed from the Topsides UPS, or has its own. Transient protection and phase-angle correction may be required. Any over-current protection devices in the system must be co-ordinated, to ensure that only the fuses/devices for a faulty SCM operate and do not trip the main supply for the rest of the system.

10.2 Components 10.2.1 General A typical EPU comprises the following components: a) b) c) d) e)

Main input circuit breaker. Power Transformer & Isolation. Output circuit breakers and current limiters. Line Insulation Monitor. Controls and displays

Figure 10.2 - EPU Module

10.2.2 Main Circuit Breaker The incoming Topsides supply is routed via a main input circuit breaker, which should be lockable for use during topsides or subsea maintenance. The isolator is often interlocked with the EPU access door in order to ensure supply is isolated before the door can be opened. Warning labels should advise the consequences of opening the door. The contact breakers may be equipped with over-current and over/under-voltage trips to protect the unit.



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10.2.3 Power Transformer/Power Stage & Isolation An isolation transformer converts the incoming supply voltage to the level required for subsea transmission. If the incoming supply is of the wrong frequency or requires other treatment, then a power conversion stage may be employed, such as a switched-mode regulator or other power-supply technology. With these devices, care must be taken to ensure unwanted harmonics are not transmitted subsea (could interfere with the communication channel via cross-talk) or are reflected back to the Topsides supply.

10.2.4 Output Circuit Breakers & Current Limiters Outputs are usually fed via circuit breakers with thermal and magnetic trips and/or fuses rated according to the subsea control system requirements. The circuit breakers should be lockable in the off position, for maintenance purposes. The circuit breakers are often provided with auxiliary contacts for remote indication to the MCS. In some system designs where subsea held-on solenoids form part of the ESD system, a relay connected to an incoming ESD signal may trip the output supplies, in which case a manual 'reset' button is included to avoid un-wanted restoration of power after the ESD condition is removed.

10.2.5 Line Insulation Monitor The insulation between line and earth on both power outputs should be monitored by a Line Insulation Monitor (LIM). The LIM should have two levels of operation:

•

Level 1 - At a pre-set level should indicate only "Pre-trip warning".

•

Level 2 - At a pre-set level should trip the output circuit.

The LIM should be rated and / or compensated for use with subsea umbilicals of the construction and length required for the application.

10.2.6 Controls & Displays Each of the dual output supplies should have the following indicators mounted on the front panel:

• • • • • • •

Voltmeter (if the output supplies use 3 phase, the voltmeter should measure line to line and be switchable between phases). Ammeter (for 3 phase, the ammeter should measure line current and be switchable). Frequency meter. Line insulation fault lamp. Output-on lamp. Output-tripped lamp. Line insulation resistance.



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10.3 Testing The EPU should be subjected to a witnessed Factory Acceptance Test (FAT) procedure. The acceptance testing should include, but not be limited to:

• • • • • • • •

Heat soak tests / Burn in period. Visual checks on workmanship, cable marking etc. Insulation testing cores to ground and each other. Continuity testing. Earth continuity tests. Circuit breaker tests. Line Insulation monitoring tests (particularly as regards usage with subsea umbilicals and long-term Testing). Operational tests over the full range of input / output voltage, frequency and loads, and start-up surges.

10.4 Maintainability EPUs are usually modular in design, allowing for access to all components for maintenance or repair, and for isolation of individual power supplies. Interlocks are often implemented on the access doors, such that internal power is switched off when the doors are opened (over-rides are often available should it be necessary to maintain subsea power).



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11 UN-INTERRUPTIBLE POWER SUPPLY (UPS) 11.1 Description 11.1.1 General As referred to in the section on the Electric Power Unit (EPU section 10), any electrohydraulic multiplexed subsea control system requires a secure, reliable supply of electrical power. The Uninterruptible Power Supply (UPS) is a unit which is often provided in the absence of a suitable existing supply on the Platform / FPSO. It will usually comprise of one or more racks of equipment, located in an Equipment Room. 11.1.2 System Operation The UPS will take incoming Platform power, and filter, condition and store it in associated batteries, such that an output supply is always available in the event of failure of the Platform supply itself. The UPS is usually sized to provide 30 minutes minimum and up to one hour full operation from the batteries depending on the operational requirements.

Figure 11.1 - UPS & Battery Rack

11.2 Components A UPS typically operates by rectifying and smoothing the incoming supply, converting it to direct current (dc), which can then be used to charge associated batteries. The output from the batteries is then converted back to alternating current (ac) ready for use to power the subsea system. In case of failure of the main incoming supply, the output from the batteries is quickly switched to power the dc to ac converter, thus ensuring a constant supply. The technology behind modern UPS devices is varied and sophisticated, all aiming to improving the electrical efficiency of the conversion from ac to dc and back again, and for controlling the switchover from main power to standby power.



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Constant-voltage battery chargers usually use thyristor* technology to ensure a high level of reliability and switchmode rectifiers offer very high power to volume ratios. Designs are usually modular to allow for expansion and redundancy with ‘hot swap’ capability, including microprocessor control and remote power management with full system and battery monitoring. Usually the UPS is purchased from a specialist manufacture of such devices and is not built by a subsea control system supplier. The UPS is often procured as part of the overall Platform/FPSO supply and therefore not by those responsible for the control system. The size of unit required depends on the existing and future field requirements and it is important to agree at the FEED stage the required maximum output required, especially if planning for future expansion. The field power requirement is never easy to predict and will vary with the different control system suppliers. It should be noted that space on a Platform or FPSO for such units is often at a premium, and adding a second unit later or additional batteries often causes design and implementation problems. The equipment must eliminate mains borne electrical noise, sags, surges and transient spike and offer extremely reliable and economic computer grade power, else the specification of the subsequent EPU will need to deal with these problems. The unit will also provide isolation from the rest of the platform systems and should not contravene any EMC regulations nor reflect electrical noise back into the Platform supply. Modern units provide interfaces to the Platform SCADA system, and it is not usual for the UPS to be controlled or monitored by the MCS in any way. Models are available for single or three-phase outputs.

11.3 Testing A UPS should be tested at all extremes of input and output power, temperature, and with injected mains-borne electrical noise to simulate a real Platform environment. It is desirable to test it with the EPU and remaining subsea system as part of an SIT if possible, although, as mentioned above, it is often procured separately to the Control System and is therefore rarely available until commissioned offshore.

* Thyristors are semiconductor components whose fast-acting switching characteristics allow the construction of high-efficiency direct- to alternating-current converters, which are at the heart of UPS designs, whereby the d.c. output of batteries is converted back to an alternating supply for the equipment connected to it, as detailed in 11.2. Being either 'on' or 'off', there is (theoretically) no power dissipation within the thyristor device itself. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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12 HYDRAULIC POWER UNIT (HPU) 12.1 Introduction The Hydraulic Power Unit (HPU) is a skid mounted unit designed to supply water based biodegradable or mineral oil hydraulic fluid to control the subsea facilities that control the subsea valves. A typical HPU has a supply reservoir and return reservoir, pumps for each pressure system and a circulation pump for filling and flushing. The reservoirs, tubing, and wetted parts of all components including hydraulic pumps, hand valves and control valves will be of 316 stainless steel to prevent corrosion and contamination in the hydraulic system. The two hydraulic system pressures are low pressure (LP) for the Xmas tree valves and high pressure (HP) for the sub-surface safety valve (SCSSV). Each system usually has duty and standby pump systems for back up and maintenance purposes, although for some systems a common back up pump is used. For redundancy, dual systems usually have an electrical driven pump and an air driven pump for each pressure system in a lead/lag configuration. A bank of accumulator bottles with an internal bladder or piston and Nitrogen pre-charged stores the energy from the pump discharge to prevent frequent cycling of the pumps. The pressure pumps are gravity fed from the supply reservoir. Each pump pressure system discharges through a dual filtration unit, charges a bank of accumulator bottles, and outlets the skid into the umbilical system. There are hand valves for manual isolation and solenoid valves for safety shutdown of the umbilical system. The system can be an open hydraulic system where fully biodegradable spent hydraulic fluid is dumped to sea, or a closed system where spent hydraulic fluid flows along the return line in the umbilical to the return reservoir. The return reservoir has multiple service duties. It receives the return hydraulic fluid from the umbilical of a closed hydraulic system. It receives fluid from the manual or automatic vent of the skid or accumulators, or from the system relief valves. It is also used for filling the system. For closed systems with no leakage, there should be no requirement to refill the reservoir, but open systems will require topping up from time to time. The frequency of topping up is dependent on the frequency of operation of the subsea valves. The final service of the return reservoir is for flushing and cleaning the hydraulic fluid to the required system cleanliness before transferring to the supply reservoir. A high flow multi-purpose circulation and transfer pump with filters is provided for flushing the return reservoir, transferring of hydraulic fluid between reservoirs, and for filling from external sources. The pump can also be used for flushing the supply reservoir if necessary. The control of the system for the HPU can be local control with a remote warning alarm, or can be operated remotely via the Platform DCS or the subsea system MCS, although this latter method means that the HPU is then not a self-contained unit.



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The HPU has a local control panel for indication of hydraulic system pressures, hand/off/auto selectors for the pumps, and duty/standby selection for the pumps, and emergency stop controls. The panel will also have a common alarm lamp, and an audible alarm horn. The common alarm can also be provided at the Master Control Station or DCS.

Figure 12.1 - Hydraulic Power Unit



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Fluid Fill

Hand Selector Valve

Return Tank

Flushing & Fill Pump

Filter

Hand Selector Valve

SUBSEA CONTROL SYSTEMS Relief Valve

HP Pump 2

HP Pump 1

LP Pump 2

LP Pump 1

Supply Tank

Filter

HP Accumulator Bottles

LP Accumulator Bottles

S

HP ESD Valve

S

LP ESD Valve

HP Hydraulic Supply to Umbilical

LP Hydraulic Supply to Umbilical

TotalFinaElf DEEPWATER REFERENCE BOOK

12.2 Hydraulic Schematic

Figure 12.2 - HPU Schematic

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12.3 Equipment Description 12.3.1 Supply Tank The supply reservoir is fabricated from stainless steel. Its size is determined by hydraulic analysis depending on the number of wells and an agreed philosophy for the number of subsea operations allowed before refilling the tank is required. The reservoir is atmospheric, and is fitted with a micronic breather element and flame arrestor to prevent contamination of the fluid by airborne particles and risk should subsea gas permeate into the system. The reservoir is fitted with an external level gauge for fluid level indication. The reservoir has level switches for high and low alarms and for low-low pump trip. The tank has valved connections for filling, draining, and for fluid sampling. There is also a connection from a selector valve on the circulation pump circuit. It is normal also to have remote indication of the fluid level in the supply reservoir.

12.3.2 Return Tank The return reservoir is fabricated from stainless steel. Its size is determined by hydraulic analysis depending on the volume required to supply the system, and the return volume of hydraulic fluid from the subsea system on a total shutdown. The reservoir is atmospheric, and is fitted with a micronic breather element and flame arrestor to prevent contamination of the fluid by airborne particles and risk should subsea gas permeate into the system. The reservoir is fitted with an external level gauge for fluid level indication. The reservoir has level switches for high and low alarms and a high alarm to warn against over filling the reservoir. The tank has valved connections for filling, draining, and for fluid sampling. There is also a connection from a selector valve on the circulation pump circuit. It is normal also to have remote indication of the fluid level in the supply reservoir. A return filter may be fitted to the return lines to reservoir to prevent contamination entering the return reservoir. However should this filter get blocked, it could prevent the safe hydraulic vent-down of the system on a total ESD. The return filter may be omitted from the system for this reason. A system drain is provided to remove excess fluid from the skid for vent ESD shutdown requirements.

12.3.3 Low Pressure System The LP hydraulic pressure system usually has an electrically driven and an air driven pump. Each pump has a strainer on its suction in case of the unlikely event of debris becoming dislodged somewhere in the system. Each pump has flexible hoses on the supply and discharge to eliminate vibration stresses on the fixed tubing. Each pump has a hydraulic isolation valve on its supply and discharge for maintenance purposes. The system is designed so that the pumps run on demand in a lead/lag configuration with one pump being the duty service and the second pump being the back up pump. There is no set rule as to whether the electrical pump or the air pump provides lead or lag duty. It should be noted that electrical driven pumps generally have higher flow rates than air pumps, which gives a benefit in high demand situations. However, in low demand situations an air pump may be more suitable, as it is certainly undesirable to frequently start and stop electrical motors. The electrical motor can be set to deliver the bulk of the fluid requirements when pressurising the system, with the air pump providing the last 50 bar or so. This minimises the time required to start up following an ESD.



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The pumps have a common discharge into the LP header. The LP discharge header is fitted with a 3-micron absolute dual filtration system duty/standby as a 'last chance' filter to prevent contamination entering the umbilical. Each filter housing has a pop-up indicator warning of filter clogging and a differential pressure switch to provide a high differential pressure alarm either locally or remotely. Each filter also has a bypass in case of total blockage. Downstream of each filter is a valve for bleeding off fluid pressure during filter element changing, and for taking fluid samples for hydraulic cleanliness checking. The pumps are controlled either by pressure switches or a pressure controller. Control can either be by local starter or alternatively local panel control using motor control relays or PLCs. Remote control is also an option using the Master Control Station, or the process control Distributed Control System (DCS), although this results in the HPU not being an entirely self-contained unit and imposes its requirements onto the remote process control system. The pump discharge is connected to a bank of nitrogen pre-charged accumulator bottles. The interface between the gas and the hydraulic oil can be either a synthetic rubber bladder or a piston with seal rings. The number of bottles, the volume, and the nitrogen pre-charge volume is determined by hydraulic analysis. The accumulator discharge is based on the standard gas laws. The hydraulic analysis for the accumulator sizing must also consider the hydraulic pump discharge volume and the umbilical core sizing. The resistance to hydraulic flow over long offset distances even with smooth bore hose liners can be considerable. The objective of the accumulator is to store the hydraulic energy from the pump discharge by compressing the nitrogen. When the pump reaches its high set point, it will stop. As the umbilical hose pressure decays, the compressed nitrogen in the accumulator will expand and force the hydraulic fluid at the flow rated allowed by the umbilical. Panel mounted local pressure gauges will display the pump discharge pressures, and the accumulator header pressure. Pressure transducers will also output a 4-20mA signal to enable these pressures to be displayed on the Master Control Station or DCS VDU. These signals may also be used to provide low pressure alarms. The ESD cause/effect charts will usually determine that a total fail-safe vent hydraulic facility is provided in the HPU which will enable the subsea facilities to fail safe closed if there is a loss of subsea communications (i.e. failure to perform a 'commanded' ESD sequence) and/or a hazardous situation. This is achieved by fitting one or two solenoid valves in the LP Hydraulic discharge header from the HPU. The solenoid valves are three-way spring-return fail-closed ESD solenoid pilot valves. The umbilical volume from the solenoid vent port flows back to the return tank. Following an ESD (where power has been removed from these solenoids), it is usually necessary to manually reset these pilot valves from within the HPU. This prevents inadvertent start up of the hydraulic subsea system when platform power is reapplied.

12.3.4 High Pressure System The high-pressure pump system is similar to the LP system. The operating pressure is dictated by the force required to overcome the shut in well pressure and open the SCSSV. The volume requirements are lower and the pump flow rates will be less. The hydraulic analysis will also dictate that the accumulator volumes will also be smaller. The operating and test pressure requirements for HP systems often border on the design operating limits of conventional seamless stainless steel tubing and compression fittings necessitating the use of high strength tube and high pressure fittings. Again, use of an electric pump can greatly speed the system re-pressurisation following an ESD. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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12.3.5 Circulation/Transfer Pump System For Reliability of the subsea system, it is very important that the hydraulic fluid already in the tank system, and when filling the tanks is clean to the required standard. The standard is NAS 1638 Class 6. The circulation / transfer pump is dual purpose. It can be configured to flush the supply tank to the required cleanliness, or alternatively configured to fill the return tank from an external source. The pump motor is manually controlled. The circulation / transfer pump is a high flow rate transfer pump and not a pressure pump. The pump must be sized to provide adequate flow rate achieving a Reynolds number greater than 3,000 to ensure turbulent flow conditions and effective flushing is achieved. To drive a high flow rate pump, an electrical motor is required. A hand valve on the pump suction is used to manually-select the pump suction source. The sources are the bottom of the supply or return reservoirs, or the return tank filling source. It is imperative that one of these valves is open before starting the pump. This valve is usually left in the 'circulate' position for normal operation. The pump discharges through a check valve into the 3-micron absolute high-capacity dualfiltration unit provided for flushing the hydraulic fluid. Each filter has a pop up indicator on its housing to indicate if the filter is blocked. A sample point is provided on the filter outlet for sampling of the hydraulic fluid to verify its cleanliness. The filter unit is configured in a duty/standby configuration for continuous operation during filter changeout. The discharge from the filter can be routed either to the supply tank or to the return tank. Selection is by a hand selector valve adjacent to the filters on the discharge side. In normal operation, the fluid is transferred from the supply drums into the return tank. The fluid is then flushed in the return tank, and sampled until it is verified clean to the required standard. Only when this standard has been achieved should the fluid be transferred from the return tank to the supply tank.

12.3.6 Bulk Fluid Storage Under 'normal' use, where the subsea valves are not being frequently operated, the fluid in an HPU can last a considerable time. However, at some point re-filling is required - with the system described above barrels of pre-mixed fluid must be brought to the HPU location and transferred to the reservoirs. It can sometimes be advantageous to maintain a separate 'bulk' storage reservoir located in a more accessible area. These are usually available from the fluid suppliers and can be exchanged in their entirety for fresh units.

12.3.7 Controls & Instrumentation As previously mentioned, local controls and gauges are provided to enable local control & monitoring. These are available from the exterior of the unit, protected by glass-fronted doors or a protective panel. Where electrical flowmeters are provided, there is usually a local display and reset button. An 'emergency stop' button and protected 'subsea system ESD' button are usually provided. Inside the unit itself, most instruments and major devices such as pumps have block/bypass valves to allow replacement during maintenance, and local interior and panel lighting is provided. Anti-condensation heaters are also provided where required. Sampling points for fluid quality checks are provided.



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13 TOPSIDES UMBILICAL TERMINATION UNIT (TUTU) 13.1 Introduction This Chapter describes the Topsides Umbilical Termination Unit (TUTU), being the topsides unit that routes hydraulic fluid from the HPU to the subsea umbilical. 13.2 Description The umbilical carrying hydraulic fluid electrical power/signal, and chemicals, to the subsea system is usually located on the cellar deck of a Platform, or at the edge of an anchored static FPSO or the turret of a turret moored FPSO. This is usually a considerable distance from the HPU/EPU. The umbilical itself must be terminated close to its hang-off point, so some form of termination bulkhead and electrical junction box is required. This usually takes the form of a Topsides Umbilical Termination Unit or TUTU. The TUTU provides hose coupling points and an electrical junction box, but in addition houses block and bleed valves for each hydraulic function. The hydraulic supplies from the HPU are usually carried by Platform pipework to the TUTU. The bleed valves allow this pipework to be filled, flushed and bled after construction. Similarly, they also allow the umbilical to be bled down if required. The bleed valve outputs are usually routed back to the HPU to avoid local spillage of fluid. The block valves allow a definite isolation point for the subsea umbilical. The block valves can be locked shut to prevent inadvertent pressurisation of the umbilical. This also allows the HPU outputs to be tested without having any subsea effect. Naturally, these valves must be open for normal operation and access to the TUTU is restricted by a lockable cabinet door. A drain port ensures that any build-up of pressure inside the unit caused by leakage cannot pressurise the unit. The TUTU is usually constructed of stainless steel and is either safe area equipment or certified for operation in a Zone 1 or Zone 2 hazardous area as dictated by the specified hazardous area location. The connections to the umbilical are usually arranged on the side of the unit, at an elevation that allows a generous radius for connection of the umbilical pigtails. This often requires that the TUTU itself be mounted at about 1 metre from deck level, so the unit may have a plinth. If bottom entry is required, then a transition box is required to allow pull-in of the umbilical for hang-off and to then terminate the hoses in the bottom of the box.

Figure 13.1 - TUTU Umbilical Termination Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Provision is usually made for enclosing the pigtails from the umbilical hang-off inside a length of protective conduit. Depending on the umbilical termination design, this may require one or two such conduits to house both the hydraulic hoses and electric cables, and the TUTU mechanical design must consider this. The electrical junction box is not usually located within the hydraulics enclosure and should preferably be kept isolated. It is usually mounted on the side of the unit. Typical TUTU

One Hydraulic output Shown Only

Figure 13.2 - TUTU Block Diagram

13.3 Termination of Chemical Hoses A similar item of equipment may also be provided for connection of the chemical hoses, although this is usually kept separate from the control system hoses and cables to avoid contamination. This "Chemical Umbilical Termination Unit" is placed adjacent to the TUTU by the umbilical hang-off point. Again, precautions must be taken to avoid pressurisation of the box due to chemical leakage (particularly with the known phenomenon of migration of methanol through thermoplastic hoses, which can then travel to either extremity of the umbilical). It is usual for the termination box design to include a Methanol catcher when Thermoplastic hoses are used.

Figure 13.3 - Internals of a typical TUTU Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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14 UMBILICAL This section included for completeness, as part of Figure 8.1 page 30. Umbilicals are detailed in the Deepwater Field Development Reference Book - Umbilicals.

15 SUBSEA UMBILICAL TERMINATION UNIT (SUTU) 15.1 Description & Components The Subsea Umbilical Termination Unit (SUTU), is the termination that mates with the umbilical flange for installation and pull-in of the umbilical to the required subsea structure. This unit is sometimes known as an Umbilical Termination Assembly (UTA) or Unit (UTU). The SUTU terminates all of the elements (hoses, cables or tubes) of the umbilical and provides outputs for the jumpers which connect the SUTU to the SDU enabling the subsea distribution. The SUTU is fabricated from carbon steel coated in accordance with a suitable subsea paint specification. The SUTU has a mounting flange for the umbilical armour flange termination, and mounting plates for the hydraulic, chemical and electrical connectors. The hydraulic and chemical connections are mechanical connections to the back of male hydraulic connectors, and the electrical cables terminate in subsea mateable electrical connectors (which contain pressure balanced and oil filled housings for the connections themselves, with cable boot seals onto the outer sheath of the cable conductors). The SUTU can be designed to be pulled into a subsea structure. To deploy this design needs special rigging and reaction with the ROV to pull into the subsea structure. This can be a slow task in deepwater. Alternatively, the SUTU can be designed to be deployed vertically into a stab assembly on a structure. The stab has a hinge device, and when the SUTU is locked into the stab, the lay vessel starts to layaway and the hinge device will rotate to orientate the umbilical into the horizontal plane, and the umbilical can be laid away by the lay vessel. With the umbilical in the horizontal plane, the SUTU connector plate is also in the horizontal plane. This allows the ROV access to make up the jumpers to the SDU. A SUTU design that plugs directly into the SDU is feasible, although this restricts the order in which the units must be deployed and prevents the retrieval of the SDU without first removing the SUTU/umbilical. One other scenario is that the umbilical SUTU and the SDU are combined into one unit with a flange for termination of the umbilical and terminations for the hydraulic, chemical and electrical connections. This unit would retain the name of an SDU. The overall size and weight of such a unit, however, makes it difficult to store on an installation reel, forcing a firstend installation, or making a carousel necessary and is difficult to deploy in deepwater. The advantage is that the connection between the umbilical and SUTU is made (usually) at the factory and the whole can be tested as an assembly. Neither of these allows the use of a protective weak-link device unless one is specially designed as part of the overall interface between the two items. In both this and the above cases, the units and their mounting structures must be designed to accommodate the maximum expected umbilical loads, making them considerably larger/heavier.



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16 WEAK LINK 16.1 Description & Components A weak link is a device used to protect equipment that is permanently installed on a manifold or template, so that in the event of an umbilical being snagged, the umbilical will break away, activating the link and shearing jumpers connecting to the fixed subsea equipment. A weak link may not be required, especially in deepwater applications. The need for the weak link depends on the subsea system architecture, and the risk analysis of snagging by anchors, etc. A weak link is usually a guillotine device that has one part fixed to the template/manifold or to the SUTU itself. The other part assembled using slide guides is attached to the umbilical termination (SUTU). The weak link is generally made from 316 stainless steel and is unpainted. Load calculations must be performed to ensure that whichever structure it is attached to can take the loads imparted before the device shears the umbilical. Subsea jumper hoses and cables pass through guide holes in both parts of the guillotine. The jumpers attach to the SDU at one end termination, and to the SUTU at the other end termination. When the weak link is being handled or the SUTU attached, an installation bolt is used to ensure that the weak link is not activated. After the installation is complete, the installation bolt is removed and the two guillotine parts of the weak link are then held together by a shear pin. The shear pins are batch made and type tested to verify that the shear force is within the design tolerance. The shear force is specified to accommodate the snagging load requirements. As the shear load has to be activated in a straight line, guide funnels are required on the subsea structure to ensure correct operation of the weak link mechanism. The holes for the jumper hoses and cables are staggered to provide an offset for cutting of the elements. Otherwise with hoses constructed with elements such as Kevlar braiding, the weak link can jam and not activate properly. The jumper hoses and cables, which are neutrally buoyant in seawater, are not secured through the weak link device. Therefore, in applications where there are strong seawater currents that cause movement of the jumpers, guide sleeves are used to protect the hoses and cables from chafing against the weak link edges. The sleeves also protect the cutting edges of the guillotine from inadvertent damage during handling. Alternative designs of weak-link exist whereby the hydraulic & electrical sections disconnect using couplers/connectors, effectively acting as a large 'plug and socket'. These 'non-destructive' designs in theory allow a disconnected umbilical to be simply reconnected.



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However, the mechanical installation requirements for a deepwater application render the design more complex, and in any event the disconnection forces still have to be made to act in a straight line.

Figure 16.1 - Weak Link



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17 SUBSEA DISTRIBUTION UNIT (SDU) 17.1 General The Subsea Distribution Unit (SDU) is sometimes also known as the Subsea Distribution Box (SDB). The SDU connects to the subsea umbilical through the Subsea Umbilical Termination Unit (SUTU), and distributes hydraulic supplies, electrical power supplies, signals, and injection chemicals to the subsea facilities. The facilities can be a subsea template, a satellite well cluster, or a distribution to satellite wells.

17.2 Construction The SDU frame is fabricated from carbon steel coated in accordance with a subsea paint specification. The frame is designed for lifting and lowering onto a location on a subsea production structure. Alternatively, the SDU can be located on a mudmat, simple protective frame, or a mono-pile.

17.3 Interface with Umbilical The SUTU can connect to the SDU with a vertical stab and hinge-over connection, or alternatively connect via electrical and hydraulic jumpers at seabed level pull-in location, or manifold structure pull-in location using ROV or diver* -mateable connectors. If the field layout demands, the jumpers can route through a weak link breakaway connector.

17.4 Interface with SCM The jumpers from the SDU to the SCMMB connect using ROV or diver- mateable connectors. Refer to Section 16 for Jumpers.

17.5 Electrical Distribution The electrical distribution is usually contained in an oil-filled pressure-balanced fabricated and coated carbon steel housing called an Electrical Distribution Box (EDB) or Unit (EDU). (Non pressure-balanced resin-filled junction boxes are sometimes used, but these do not allow future maintenance and require the encapsulated components to be suitable for use at depth; designs requiring current-limiting devices may be housed in a one-atmosphere enclosure). Entry and Exit of the EDU is by flange mounted electrical controlled environment type connectors. The connectors are configured so that any connections that may be accidentally disconnected live, have the live conductors protected from the seawater. Cable tails from the back of the electrical connectors within the oil-filled housing are connected for distribution as required by the control system architecture and the system redundancy capability. The cable connections are usually spliced by crimping and have the insulation reconstituted by moulding. The requirement for fault protection is dependent on the system design and the number of wells that could potentially be disabled by a subsea cable fault. There are three types of electrical protection used - fuses, circuit breakers, thermal re-setting trip devices.

* Here 'diver' implies the use of a suitable deepwater diving suit such as 'JIM' or NEWT-suit. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Fuses are not effective, as slow blow fuses are necessary in order to cater for the inrush current whilst charging up the umbilical. This makes fuses ineffective in isolating a fault in the distribution system without over-loading the remainder of distribution outlets, and generally, a fuse would not blow before the line insulation fault trip in the EPU is activated. Circuit breakers have been used subsea in EDUs, but are not commonly used as the circuit breaker reset mechanism has to penetrate through the EDU housing using O-rings which introduces a potential fault path.

Figure 17.1 - Electrical Distribution Unit The thermal re-setting devices are semiconductor devices and due to the technology required, they are not available from all suppliers.

17.6 Hydraulic and Chemical Distribution The hydraulic distribution is by tubing from the incoming interface connection routed around the structure to the distribution outlets. The stab connections and the tubing are generally of 316 stainless steel. The tubing terminations are all welded for integrity. The tubing, which is usually installed at a fabrication site, has to be flushed and cleaned to the integrity required by the subsea control system. Chemical injection systems generally require larger volume flows during normal operation, and are also subject to increased viscosity at lower seabed temperatures. Therefore, larger bore tubing or piping is generally used, again welded to maintain integrity. Multi stab plate hydraulic connections must have some movement in order to allow for alignment during make-up. Also tubing is often installed on structures using clamps with plastic inserts. This can leave the tubing and end connections floating without cathodic protection. It is essential that these items be electrically bonded to the main structure cathodic protection system to avoid rapid corrosion of the system.



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Other material that may be considered for the distribution piping or tubing is carbon steel for the chemical injection system, or more exotic materials such as Duplex or Super Duplex stainless steel.

Figure 17.2 - Hydraulic Distribution Unit To ensure correct mating of the respective parts, guide pins are used on stab plates, and single connections may have different size quick-connect couplings or may be keyed.

17.7 ROV Connection The size of an ROV means that design consideration regarding access to the SDU has to be carefully considered. It is not always necessary to have a docking station for ROV make up, but docking may make certain tasks easier. If the field survey shows strong currents at the seabed and changeable directions, then ROV docking is necessary. With multi-well applications where the ROV must remove connectors from parking positions and hook up at positions on the SDU, it is essential that the ROV does not get entangled in any of the other jumpers. This can cause damage to the jumpers or may entangle the ROV where it would need to cut jumpers in order to free itself. Clear marking of the connection point is essential in order that the ROV pilot may orientate the ROV at the desired location and to ensure the correct hook up in low visibility subsea. See markings in Section 24.



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18 SUBSEA ACCUMULATOR MODULE (SAM) 18.1 Introduction This Chapter describes the Subsea Accumulator Module (SAM), being the subsea unit that stores hydraulic fluid such that adequate pressure is always available to the Subsea system even when other valves are being operated.

18.2 Description When a subsea system is required to operate a number of trees located along distance away from the host Platform/FPSO, the hydraulic fluid from the Topsides HPU will take a considerable time to reach the subsea equipment, particularly where small hoses are used in the umbilical. This can result in a drop in pressure at the subsea tree when a valve is opened, as the pressure cannot then be restored immediately via the umbilical. If the pressure drops, other open tree valves may begin to close, before the pressure can be restored. If the pressure drops too much, the pilot valves in the Subsea Control Module will 'drop out' i.e. close, causing one or more tree valves to close irrespective of whether pressure is then restored via the umbilical. In order to maintain an adequate level of pressure at the subsea location, some degree of local accumulation may be required. This can be provided by individual accumulators on the SCM itself, but more usually, a self-contained skid containing several Accumulator bottles is often provided, this being termed a 'Subsea Accumulator Module' or SAM. The SAM will house sufficient LP Accumulation to maintain pressure during valve operations. In addition, it is also sized to hold sufficient fluid to perform a number of subsea control operations, even if the supply from the surface no longer functions, thus giving a degree of reserve power. A trade-off must be made against the size of skid required and the amount of accumulation, and this is done via a Hydraulic Analysis performed by the Supplier against the Client's Specifications. Sometimes the analysis will demonstrate that HP accumulation is also required. The requirement for an increased Nitrogen pre-charge pressure in deep water applications will decrease the efficiency of subsea accumulation, which will increase the number of accumulator bottles required.



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18.3 Components A SAM is a simple skid, primarily housing Accumulators. Nevertheless, it must be designed, manufactured and tested as part of the overall system, and designed to be retrievable for maintenance, as the accumulator pre-charges may periodically need replenishing. The design may also incorporate a filter and block/bleed valves to allow flushing and testing.

Typical SAM (LP only)

Figure 18.1 - Subsea Accumulator Module Block Diagram The SAM is usually a stand-alone skid, connected via a mounting base, which is connected to the SDU or the hydraulic tubing supplying the subsea control modules. The SAM is run and retrieved in a similar manner to the subsea control module. In order to allow the SAM to be retrieved for maintenance, ROV operable block, vent, and bypass valves are sometimes incorporated into the Manifold/Template tubing (where the hydraulic distribution is hard piped). This valve will allow production to continue whilst the unit is replaced, but tree valves should not be operated whilst the bypass is in operation, due to the risk of pressure-drop as outlined above.



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Figure 18.2 - Subsea Accumulator Module

When block and vent valves are not used, the SAM can be retrieved by pulling off its mounting base and relying on the self sealing quick connect hydraulic couplings sealing to maintain the pressure in the hydraulic system. Installation of the SAM is more difficult, as there is a large force required to mate the SAM and SAMMB against the closed force exerted behind the closed hydraulic poppets. It is essential that the hydraulic quick-connect couplings used in this application are fully pressure-balanced to counteract the coupling mating forces, particularly in deepwater applications. A running tool is required to run and set the SAM onto the SAMMB in deepwater applications.



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19 INTERCONNECTIONS 19.1 Introduction Jumpers are required to connect between the fixed items and installed items in the subsea system. The jumpers can be hydraulic, chemical, or electrical, or a combination of all three. The jumpers connect between the umbilical SUTU and the SDU, the SDU and the SCMMBs etc. A jumper can consist of a single hose or cable with ROV connection or can consist of a stab plate assembly for multiple installation and hook up. Stab plates can be guided and screwed into position or alternatively can be guided into position and secured with a clamp hub arrangement. Jumpers for hydraulic systems are constructed from hose with hydraulic sealing terminations. For deepwater applications high collapse resistance hose (HCR) is required to prevent hose collapse. Alternatively steel tube may be used for jumpers, which also provides resistance to chemicals and eliminates chemical compatibility issues. Electrical jumpers usually consist of a reinforced hose conduit outer sheath terminated to an electrical connector at both ends. Inside the sheath, single insulated copper cores are terminated to the conductor pins on the back of the connector water block and the conduit is filled with a dielectric fluid for integrity and also to provide a pressure balanced system for deepwater applications. Jumpers can be hoses, steel tubes, steel tubes oversheathed, and cables bundled together, or alternatively a jumper can be laid up and oversheathed in a similar manner to the outer sheath of an umbilical. 19.2 Fixed Stab Plate A fixed stab plate is required on the SDU, SCMMB or manifold structure to terminate the fixed hoses and cables and to interface with the flying ROV stabplate of the jumper assembly. The stabplate is usually mounted in a vertical plane, and electrically bonded to the cathodic protection system of the mounting structure. The stab plate has to be in a suitable location so that the ROV pilot can correctly identify it and fly in the ROV with the stabplate attached for installation and hook up.

Figure 19.1 - SDU Fixed Stabplate The stabplate is populated with male hydraulic couplings and also electrical connectors if required. There is a central receptacle for the entry of the lead screw arrangement for the male stab. Also there will be a guide sleeve for the male guide pin insertion, which provides the fine alignment of the plates prior to the mating of the couplers. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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19.3 ROV Stab plate The ROV free stab plate comprises a flat plate populated with female hydraulic couplers. It can also include electrical connector receptacles. Mounted to the centre of the plate is the drive screw assembly. The screw shaft nose provides the initial engagement with the fixed stab plate, and the lead screw provides the means of engaging the free and fixed plates together. The lead screw is made of dissimilar material to the threads in the fixed stab plate to prevent galling. Mounted towards the top of the stab plate is a grabber / guide pin assembly. The guide pin provides additional guidance as the two plates come together and ensures the plates are aligned for coupler and connector engagement. The grabber shaft proves the means for the ROV to support the weight of the stab plate. The torque tool and grabber interfaces are usually designed and manufactured in accordance with API 17H and allow the stab plate to be deployed using an ROV Tool Deployment Unit (TDU). A jumper termination bracket at the bottom of the stab plate provides a clamp for the jumper bundle for retention and strain relief for the hose terminations, and a location eye may be provided for a strain relief member. Where steel tubes are used in a stab plate termination, there has to be consideration for the weight of the tubes due to ROV capacity and the bending radius of the tubes with respect to the location of the fixed stab plate.

Figure 19.2 ROV Stabplate with lift handle, ROV Bucket & Locking Screw

19.4 Clamp Hubs An alternative method of connection to the vertical mounted fixed stab plate described above is that the two end terminations to be connected face upwards. A U – Jumper with downward facing terminations is then lowered and guided onto the upward facing connections. Split clamp hubs with horizontal lead screws are then used by the ROV to finally mate the two sealing faces.

19.5 Electrical Jumpers Electrical jumpers can be a single assembly with a single conductor pair or multi conductor pairs terminated into controlled environment connectors. The free connector has an ROV grabber handle and the ROV pushes into the guide for the fixed connector. The guide has an orientation key and when the orientation is correct, the connector halves mate guided by a fine alignment guide. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Figure 19.3 - ROV Installed Electrical Jumper Termination The female conductor pins are enclosed in a pressure balanced dielectric oil filled controlled environment. During make up the male connector pins pass through a wiper seal and through dual redundant compensated barriers to ensure that final make up is within a totally oil filled environment. After the connector is fully mated the ROV releases the grabber handle. Removal is the reverse procedure. It may be necessary to provide a jumper to connect several transducers into a multi-pin connector at the bottom of a subsea control module mounting base. The illustration below shows a jumper with a flange mounted termination with connections for three single connectors which locates on a vertical face of a SCMMB, which has a cable conduit exit at the rear, and the other jumper end terminates in a multi-core connector in the module mounting base.

Figure 19.4 - Single Electrical Jumper with three outlets



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19.6 Hydraulic Couplers The hydraulic couplers for deepwater applications need a strong enough spring to seal against the external pressure head in order to prevent the seawater contaminating the hydraulic fluid, but also to be of a design where only a low pressure force is required for make up. There are couplings available that require a low force only for make up, and these are available with dual redundant resilient seals, and with a combination of resilient and metal seals.

Figure 19.5 - Low Force Coupler For deepwater applications a fully pressure balanced coupling is preferable. These are fairly new concepts, but are available in single coupler pair design, and also the four coupler hydraulic circuit HydraQuad™ design. The single pair is a resilient seal design with a porting design that allows an inherent pressure balancing across the poppets, which provides a pressure assistance to the spring closure force when the coupling is disconnected. The HydraQuad™ design uses a combined metal and resilient seal arrangement acting in a shear seal arrangement as the coupler mates and disconnects. Both designs use the principle that the flow path is radial and hence produces no resultant separation force.

Figure 19.6 - Pressure Balanced Hydraulic Coupler Concept It is important that there are adequate flow paths through hydraulic couplers to ensure that adequate hydraulic response times are achievable. Also that the poppets are balanced to prevent the poppets being driven hydraulically from the central open position and sealing against one of the seal faces. The female couplers are usually assembled into a hydraulic jumper stab plate in order that they may be retrieved and the seals replaced if necessary. The female couplers are assembled so that they are floating on the plate to allow for any manufacturing tolerances. The back of the connectors have to be terminated to screw on hose termination couplers or by screw seal or welded assemblies for the termination of steel tubing.



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JIC hose terminations which swage inside the central core tube of a standard thermo-plastic hose can only be used when the hose can be maintained full of fluid of a specific gravity equal to or similar to the specific gravity of seawater. This is to prevent collapse of the hose in deepwater applications. Alternatively high collapse resistance hose (HCR) with a spiral flexible metal former under the core tube must be used. The flexible inner core is designed to withstand the external seawater pressure and to prevent the hose core from collapsing. The HCR hose requires a different type of coupling which has a welded construction. The metal former inside the coupler slides inside the spiral hose support and seals by swaging onto the outside of thermo-plastic liner.

Figure 19.7 - HCR Hose & Termination Cross Section When stab plates are densely populated, it can be difficult to turn and orientate all of the hoses through ninety degrees and into the hose/cable restraint. Right angled connectors are used to orientate the hoses into the clamp. It may also be necessary to have these connectors of stepped heights in order to allow hose make up and to avoid tight bends or kinking of the hoses.

19.7 Fibre Optic Jumpers Fibre optics are not commonly used in subsea control systems, but are increasingly being used in downhole applications where high pressure and temperature measurement is required. However fibre optic technology is well proven in the telecommunications industry and the subsea fibre optic has been proven and is in use in seismic applications at greater depths than currently required in the oil industry. The fibres themselves are manufactured into a steel tube conduit. The fibres are terminated into the back of the connector where the fibre is ferruled and polished and as the termination assembly is a precision fit the fibre is routed in a low stretch flexible conduit in the same manner as an electrical jumper but requires jointing. The joint box size or fibre management system is adequate to accommodate the bending radius of the fibre in order that any excess fibre can be coiled. The joint is made using a low loss fusion splice that is protected by recoating the fibre or by using a heat shrink splice protector. The compensation oil used for fibre optic jumpers is silicone oil that is known not to degrade fibre optic properties. The connector design is such that the fibre ends are protected in the compensating oil environment and not exposed for make up until the two connector outer shells are made up. The two fibre halves are aligned using a sleeve which guides the outer ferrules to align the fibres, and when the fibres touch one is spring compensated to allow for any over length tolerance. Hybrid connectors exist capable of packaging a combination of electrical conductors and single fibres in an 8 way shell. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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There are also fibre optic connectors available with penetrator feed thru’s for connecting to down hole gauge cables.

Figure 19.8 - Fibre Optic Connector

19.8 Jumper Deployment As jumpers are not usually armoured and rely on their own inherent strength a deployment tool or device is used to assist the ROV. This can be a pallet where the jumpers are laid onto the pallet in a figure of 8 arrangement. The pallet is laid on the seabed in mid position and the ROV firstly picks up one end for installation and hook up, and then takes the second end for installation and hook up. An alternative to the above is when the jumper is installed on the subsea structure in a figure of 8 configuration hanging vertically, and the ROV pulls off the loops from the hanging device as the termination is being carried for installation at the second connection. It is essential that jumpers are designed in terms of size and weight around the planned installation method. It is necessary to understand the size and capability of a work class ROV in order to correctly specify jumpers and their terminations.

Figure 19.9 - Jumper Deployment Frame



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19.9 Jumper Retrieval Both single connectors and stab plate jumpers are precision assemblies with tight manufacturing tolerances for ease of assembly and good fit when new. If a failed jumper has to be retrieved for replacement, it is essential that the jumper also comes apart. When connectors have been in service for some time they can be covered in marine growth and also subject to calcareous growth on outer surfaces. This can make them hard to disassemble. Connectors and hydraulic couplings must be designed taking retrieval into consideration. Some electrical connects have a collet latch with shear pins which allows the latch mechanism to breakaway if excessive retrieval loads are required. The latches are easy and cheap to replace.



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20 SUBSEA CONTROL MODULE MOUNTING BASE (SCMMB) 20.1 General The SCMMB is the interface between the control module and the Xmas tree or manifold/template functions that it is controlling and the remote sensors.

20.2 Construction The SCMMB is a welded construction, fabricated from carbon steel and painted to provide corrosion protection. It is bolted and earth bonded to the protective structure.

20.3 Interface with SCM The mating interface with the SCM is a horizontal stainless steel plate with the connections vertically upwards. For an ROV installation, there are vertical tubes with an ROV locking interface as per API 17H. The ROV docks, lands, and deploys and latches the SCM into place. A vertical face on the side of the SCMMB is used for incoming connection interfaces with the incoming electrical connectors for the power and signal cables, and incoming LP and HP hydraulic supplies.

Figure 20.1 - Typical SCMMBs 20.4 Workover System Interface The vertical face of the SCMMB may also be used as an interface with the Workover control system via a stab-plate connection. Removal of a crossover plate disconnects the hydraulic functions from the SCM, and connection of the work-over stab plate enables connection directly to the Xmas tree production valves, and also connection of the additional work-over valve and test functions.



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20.5 Interface with Tree Valves & Sensors The permanent connections from the SCMMB to the Xmas tree are by connections on the underside of the stainless steel interface plate. The connections from the hydraulic couplings are by tubing to the Xmas tree valve actuator functions. The electrical connections are by cable assemblies pre-made to electrical connectors at both ends and tested, which are assembled to the mounting base through upward looking electrical connectors flange mounted which are fixed to the mounting base horizontal stainless steel mounting plate.

20.6 Docking Alignment The SCMMB will have course alignment and fine alignment for locating the SCM. For fine location by guide pin, the SCM will not land if the orientation is incorrect. For self-aligning SCMs, a central helix will automatically rotate the SCM to the correct orientation before it is able to land. Due to the number of electrical and hydraulic connectors in the mounting plate, there has to be an allowance for installation tolerances during make up. Therefore all of the connectors are secured through the mounting plate and not directly secured to it, allowing movement as the SCM docks and locates in position. Care must be taken to ensure electrical continuity for corrosion protection reasons.

20.7 Latching mechanism The final latching of the SCM to the mounting base is done in several ways. The central mandrel in the SCM can be pushed down operating an over centre mechanism which then exerts an upward force onto the underside of the SCMMB interface plate, and release of the SCM is the opposite by pulling vertically upwards on the mandrel. The SCM can be secured to the SCMMB by leadscrews. The leadscrews can be vertically mounted and mate the SCM to the SCMMB by screwing into the mating screw mechanism on the SCMMB. Alternatively for a cylindrical SCM installed guideline-less, the leadscrews can be horizontal, driving two halves of a clamp mechanism that mate the SCM to its SCMMB.

Figure 20.2 - Typical Latch Mechanism



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21 SUBSEA CONTROL MODULE (SCM) 21.1 General The SCM is an electro-hydraulic device that responds to electronic commands from the MCS (via the umbilical) and provides hydraulic control function outputs to the valve actuators on all of the subsea valves. The SCM will usually also interface with sensors and sometimes meters, located both on the Xmas Tree and downhole. SCMs are often located on Manifolds/Templates for controlling and monitoring manifold/template functions. All vendors have standardised their designs for SCMs. Some vendors have more than one standard design and other vendors have engineered a universal design in which the build specification dictates the actual equipping of the module in terms of control and monitoring. The design is suitable for use both on the production Xmas trees or water injection Xmas trees, or to control template/manifold valve functions. The SCM design is usually suitable for diver or ROV installation and retrieval using tools for running and latching. The SCM can also be installed using guidelines, or alternatively guideline-less, again requiring tools for latching.

Figure 21.1 - Subsea Control Modules

21.2 Housing The SCM housing is a fully fabricated welded construction in painted carbon steel. A lift mandrel penetrates from the upper housing for lifting and installation purposes. A purpose built running tool is required for installation as current SCMs are too large and heavy for an ROV to free swim and install without added buoyancy.



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21.3 Mounting Base An SCM is usually designed to fit onto a dedicated Mounting Base (SCMMB). This is described further in section 20. The SCM is designed so that it will only fit on the mounting base in the correct orientation. The orientation can be achieved with guide pins that prevent incorrect mating, or with a centre helical guide-pin, that will orientate the SCM on landing. The SCM incorporates a mechanism for locking down onto the module mounting base after installation. This can be ROV activated by a special tool which pushes the SCM down onto the mounting base and locks it in position using an over centre mechanism that pushes up onto the lower face of the module mounting base, or alternatively it can be a twin screw lock device.

21.4 Interfaces There is a substantial force to overcome the mating force of self sealing hydraulic couplings in deepwater, and pressure balanced couplings are used for this requirement. The SCM will have 4-20mA driver circuits for monitoring external sensors for pressure, temperature, and choke position on the Xmas trees. Optional circuits provide inputs for downhole pressure / temperature gauge monitoring, by installing the gauge in a mandrel in the production tubing string.

21.5 Connections Additional monitoring functions can be provided for items such as Sand Monitors, Flow Meters, or for functions such as Smart Well Completions. The SCM baseplate is penetrated externally to its lower face by the electrical and hydraulic connectors, and the guidance and locking mechanism. The base plate can be a sandwich plate containing hydraulic galleries or it can be a passive block for through connection to manifold blocks.

21.6 Hydraulic system Although the SCM hydraulic system is designed to fail safe closed on loss of hydraulic supply, with long offsets and in deepwater applications, the extended time for valve closure may be determined by hydraulic and safety analysis to be unacceptable. This necessitates the inclusion in the SCM of high flowrate quick-dump valves for faster shutdown. Incoming dual LP and HP hydraulic supplies feed into the SCM. Pressure transducers (4-20mA) monitor the hydraulic supply pressures and provide remote indication of supply hydraulic pressures at the MCS. Filters with 3-micron elements on the supply manifolds prevent contamination in the hydraulic fluid entering the hydraulic system. A selector valve on the LP supplies module dictates which LP supply is in service LP1 or LP2. This can be a control valve for remote actuation from the surface MCS or it can be a shuttle valve actuated by loss of pressure in one of the hydraulic lines. There is a similar facility for the HP service. The LP and HP supply manifolds are of a modularised design capable of being fitted with the correct number of Directional Control Valves (DCVs). The remaining ports either are fitted with blanking seal plates or are not drilled in order to eliminate dead legs in the system and improve integrity. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The ports of the DCVs are switched using a metal slide, which has metal to metal seals to the valve body. The metal slide has a spring to fail safe closed. To open the valve the open solenoid valve coil is energised and its hydraulic pilot directs fluid on the opening end of the slider. The slide moves and compresses the return spring, and in the fully open position connects the SCM incoming hydraulic supply to the subsea valve actuator causing the valve to open. The output from the DCV has a self-latching circuit so that the valve will remain open with the open coil de-energised.

Figure 21.2 - Directional Control Valve The DCV will fail closed on loss of the hydraulic supply, or fail closed on energisation of the close solenoid coil. Energising the close solenoid directs a pilot hydraulic supply into the return spring cavity, and onto the closing end of the slider. The commanded output functions from the Directional Control Valves exit via hydraulic couplers. The surface commands energise the respective solenoid valve coils to open and close the valves. Pressure transducers (4-20mA) mounted on the Directional Control Valves detect pressure and confirm actuation back to the MCS.

21.7 System Design For deepwater applications dual redundant Subsea Electronics Modules (Dual SEMs) are invariably used. A SEM consists of a one-atmosphere nitrogen filled pressure vessel housing containing the control and monitoring electronics. The SEM is designed to stand external pressure and to keep the electronic components in a dry one-atmosphere environment that they were designed to work in. A cover with barrel-seal O-rings seals the housing, and a cable penetrator or multi-pin electrical connector is used for the cable entry.



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21.8 Electronics Inside the SEM has circuit boards for the power supplies and conditioners, modems for communications, analogue drivers, solenoid valve drivers, and a ‘house-keeping’ monitoring capability to ensure that the electronics is working properly and alarm to the surface if a problem is detected. If additional electronics is required for equipment such as downhole pressure and temperature monitoring, this can be included in the SEM if there is sufficient space available, or alternatively in a separate SEM housing.

Figure 21.3 - Subsea Electronics Module

21.9 Construction The SCM is built up from the baseplate with the manifolds, DCVs, filters. The SEMs are installed above on cradles, and wired to the incoming power and signal connectors and wired to the internal transducers. The fabricated top cover bolts into place over the SEMs and seals with the SCM baseplate, and the housing is then oil filled using dielectric oil. The housing is pressure balanced for pressure compensation using compensation bladders.

21.10 Corrosion protection The SCM does not usually have any cathodic protection (CP) of its own. It is electrically bonded to the SCMMB using spare pins in the mating electrical connectors. The SCM is protected by the CP of the Xmas tree or manifold where it is located.



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21.11 Pressure Compensation The oil filled pressure balance SCM housing requires a compensation system to cater for the change in volume of the dielectric oil fill within the SCM for shipping and handling after FAT, through to installation. Compensation bladders are used for this purpose. The calculations need consider not just the change in volume due to depth, but also the change in volume due to temperature difference from ambient to the seabed, and also the effect of any trapped air in the compensation system. The correct sizing will ensure that the bladders are not over extended, which can cause rupture. The oil/seawater interface should be at the bottom of the SCM, and in the event of bladder rupture the seawater should maintain the oil within the SCM housing preventing seawater ingress.

21.12 Return Line Compensation During SCM deployment subsea and hook up in deepwater, there is a possibility of seawater ingress into the SCM hydraulic system via the hydraulic couplings. If this occurs there is the possibility of subsequent valve corrosion if the SCMs cannot be flushed immediately after installation. To prevent this, a return line pressure compensator is required within the SCM. The pressure compensator, which is externally pre-chargeable, maintains a positive pressure within the SCM internal hydraulic system during SCM deployment and hook-up, thus preventing any seawater ingress. DCVs are available in seawater tolerant materials, however materials selected for seawater tolerance may not provide the best technical solution in terms of long term reliability. For solenoid valves in particular, the electrical performance due to the coil and Faraday cage, and the mechanical performance in terms of the valve seat, ball, and plunger need careful consideration.



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22 SUBSEA TRANSDUCERS/SENSORS 22.1 Introduction This Chapter describes the various subsea transducers/sensors available for measurement of typical parameters.

22.2 General Subsea sensors are specialised versions of surface-located devices and must evidently be constructed to withstand the ambient pressure underwater. This results in particular aspects of the sensors design, construction and interface as outlined in this section. Certain aspects of their operation which personnel are familiar with for topsides operation are not available for subsea devices, which means that their application and mode of operation require particular attention during the design phase.

22.3 Construction All subsea sensors have to be constructed from corrosion resistant materials - Stainless Steel 316L or Duplex being typically used, particularly for the interface flange. The devices need to conform to relevant standards, such as API performance requirements and should be suitable for the specified class of service. The devices will typically be constructed using electron-beam and T.I.G weld construction to ensure maintenance-free operation, all welds being helium leak tested during manufacture. Parts of the unit in contact with process fluids should be constructed of materials to match the conditions, such as Inconel 625. It is usual for at least double-barriers to exist between the process fluid and the environment; this can be achieved in the construction of the device itself, with secondary containment chambers being provided to withstand full process pressure in the event of rupture of the measuring element. SI 289 defines requirements for equipment installed on subsea manifolds and 'tertiary' pressure containment systems are incorporated. Interface flanges need to be standard designs, such as API 2 1/16" - 10,000 psi type 6BX (API Spec 6A) and can be forged from Super Duplex stainless steel with the BX152 ring groove.

22.4 Interface with display/monitoring system 22.4.1 SCM All subsea sensors must be powered from, and relay their information to the Subsea Control Module. It is not cost-effective to provide individual connections from each sensor back to the surface and in any event, the SCM is a multiplexed telemetry system and is provided for this very purpose. The SCM provides a source of power for the sensors, typically 24 volts for a 4-20mA interface and reads the signal from the sensor, digitises it via an analogue-to-digital converter, then relays it to the surface via the telemetry system, usually in response to a request from the MCS for data from that sensor. Many SCM designs have the ability to switch off any particular sensor circuit. This safeguards the rest of the system in case of a faulty sensor or damaged interface cable, which might otherwise short-circuit the supply voltage. The drive electronics therefore also has to be protected against short circuits, and individual supplies are preferable, so that the other sensors are not affected if one fails. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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It is not usual to use this facility to switch off a sensor between readings. Whilst most modern sensors have little or no warm-up time, they may still require 1-2 seconds to stabilise and if the SCM had to wait for this period when reading each sensor, the overall system scan time would be slowed down. Furthermore, repeatedly switching an electronic component on and off reduces its reliability. A formal reliability analysis does not consider this. An SCM typically reads all subsea sensors as fast as the telemetry system allows, nominally every 2-3 minutes, and so there is little to be gained by de-powering the sensors. Similarly, the circuitry also should provide for clearing any digital readback value in case of failure of the sensor. If this is not provided locally within the SCM itself, then the MCS will usually change the displayed colour of a sensor reading to indicate fault, as well as displaying any detected under or over range alarm. 22.4.2 4-20mA system 22.4.2.1 Principle Most subsea sensors operate using a standard two-wire 4-20mA interface. That is, the equipment to which they are connected supplies an operating voltage, typically between 12 – 24 volts, and the resulting current varies between 4 and 20mA according to the value of the parameter being measured. Using a current instead of a voltage overcomes the effect of the impedance of the intervening wiring, as the current remains the same whatever the impedance. It also improves the ability of the system to withstand electrical noise. Spurious signals are superimposed on the signal being measured by varying magnetic fields (such as by AC power cables) which induce currents in the conductors. If the conductors are small and close together, these fields generate equal and opposite currents in the two conductors which cancel. In practice, a twisted pair of conductors is used to carry the signals. Loop Powered Transmitter

Sensing Element

+ -

24V Power Supply

+ -

-

Internal Load Resistor

+

Measuring Instrument

Figure 22.1 - Typical 4-20mA Sensor Loop



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A current of less than 4 mA indicates an under-range reading, usually due to a fault in the sensor. A current greater than 20mA indicates an over-range reading, again usually due to a fault in the sensor. 22.4.2.2 Distance This type of sensor can therefore operate over a distance, depending on the cable size employed, which can assure the minimum operating voltage (typically down to 12 volts) across the sensor at the maximum current required. 22.4.2.3 SCM circuitry Whilst there may be problems using a fixed supply voltage with topsides devices that have to operate via zener safety barriers* for intrinsic safety reasons, this does not apply for subsea sensors, and the SCM circuitry to operate the sensors is relatively simple. The 4-20mA signal is applied to a precision resistor, from which the resulting voltage is digitised using the SCM’s analogue-to-digital converter (usually to a resolution of 12 or 16 bits) and sent to the surface via the telemetry system as required. 22.4.2.4 4-wire device Where the sensor requires more than 4 mA in order to operate, a 4-wire interface can be employed, two being the supply and the remaining two wires being the measurement current. 22.4.3 Subsea connections Most subsea sensors now use this interface, particularly after the acceptance of subsea conductive connectors, which allow dc connections to be made, and allow 2 or 4-wire operation. The connection of the cable harness to the sensor itself is a potential leak path and must be tested during manufacture; they are sometimes not mated to each other until after delivery of the sensor itself from the manufacturer, and should then be hyperbarically tested by the Subsea System Supplier. An alternative is an integral connector in the sensor itself, which can then be tested during manufacture by the Sensor Supplier. In any event, the 'final' joint of the various subassemblies must be tested under hyperbaric conditions. Where there are a large number of sensors to be connected to an SCM, a Supplier will sometimes provide a subsea junction box, which enables a single high-density connector to be 'broken-out' to many individual sensors.

* A zener barrier is a semiconductor device that limits the energy that can be transferred from a Safe Area to a Hazardous Area even under fault conditions. A zener barrier does not itself make a circuit intrinsically safe, it merely protects the integrity of an Intrinsically Safe circuit in the event of a fault by limiting the current flow to a safe level. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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22.4.4 Electrical isolation Care should be taken to verify if a proposed sensor is, or is not, isolated from the SCM circuitry; if not, earth loops could arise once the sensor is installed onto a Manifold/Template/Tree and could affect the overall SCM operation as well as the corrosion protection system. Sometimes the manufacturing process of the sensor itself leaves the sensing element in contact with the metal body, so isolation is not always achieved. Other methods encapsulate the sensing element within a sheath and avoid the problem. 22.4.5 RFI Some sensors can be prone to Radio-Frequency Interference in that the sensing element and its wires can pick up induced voltages from nearby radio sources such as walkie-talkies. Obviously this is not a problem once installed subsea but it is preferable to take precautions in the SCM design to avoid unsuspected problems during onshore (or offshore on-deck) commissioning, 22.4.6 Calibration Once subsea, a sensor is not expected to have to be calibrated, and it is actually in a reasonably benign environment as regards extremes of pressure/temperature/shock etc. There is no easy way of detecting any drift in calibration and the manufacturer's specifications for drift are the only practicable guide to this parameter. However, it is usual to test (again) all sensors once they have been installed onto a Tree/Manifold/Template, as there is a high risk that they have received severe physical shock/vibration or mishandling during this process and sometime, over-pressurising during Manifold proof-pressure tests. 22.5 Types of Sensor The following types of sensor are available for most normal subsea measurement requirements, and will be described in more detail below. •

Pressure (PT)

•

Temperature (TT)

•

Combined Pressure/Temperature (PTT)

•

Choke Position (ZT)

•

Differential Pressure (DP)

•

Downhole Pressure/Temperature (DHPTT)

•

Sand Detector

•

Pig Detector

Figure 22.2 - Typical Sensors Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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22.5.1 Pressure (PT) Subsea pressure gauges typically operate using the force-balance technique, in which the current required by a coil to resist the movement of the detecting diaphragm gives a measure of the applied pressure. The diaphragm therefore does not actually deform and therefore devices can be built to withstand high pressures. Such devices can achieve an accuracy of +/- 0.15%, although the output current circuitry may reduce this to an overall error-band of around +/- 0.5% of full-scale. Other devices operate using a similar technique in which the change in capacitance of a sensor element with pressure is detected and typically, accuracy of +/- 0.5% can be obtained. However, it should be noted that further 'errors' are introduced into the overall system via the digitisation process between the sensor and its eventual display on the MCS. It is unreasonable to expect (and to specify) better than about +/- 2% for a pressure reading. As pressure transducers are flange-mounted, they cannot be removed subsea if they fail. It is possible to specify a transducer with dual gauges in one housing providing a dual redundant sensor. Higher accuracy can be obtained using quartz-crystal gauges and these are often used for high-accuracy Downhole Pressure Transducers (see 22.5.6) 22.5.2 Temperature (TT) Some temperature sensors operate by measuring the output of a thermocouple, which is a simple device whose output is proportional to the difference in temperature between a hot and a cold junction. The hot junction is the one measuring the process and the cold junction is at the head itself. To compensate for change in ambient temperature (cold junction) most such transmitters incorporate a compensating circuit, which needs to be co-located with the cold junction, but there is still a potential time-lag between the junction and compensation circuit which affects overall accuracy. A resistance sensor has an element, which depends only upon the absolute temperature and therefore has no cold junction compensation. The disadvantages of a resistance element are its strength, but modern encapsulation techniques can improve this. They are also larger than the thermocouple probe, which can give it a slower response time. Modern sensors are typically made by film-deposition onto a ceramic substrate. Temperature sensors present somewhat of a dilemma as regards their installation. In theory, the sensing element should be as close to the process fluid as possible. However, if the sensor were simply fitted into the production bore, there would be no other physical barrier between the process and the environment, other than the sensor itself. The usual approach therefore is to install a thermowell, or use a pocket drilled into the Tree Block. Care must be taken in matching the size of the thermowell and the sensor probe - ideally, the probe should be just in contact with the wall of the process pipe (but not damaged by differences in tolerance or expansion etc). Thermally conductive grease can improve this contact. Some installations do not consider this and therefore the temperature reading will be subject to the thermal inertia of the system. The API standard for thermowell lengths is that they should protrude sufficiently into the process flow path to be within the mainstream turbulent flow. However in pipeline applications where through pigging is required, the thermowell must not protrude into the pipeline bore.



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22.5.3 Combined Pressure/Temperature (PTT) A design of sensor is available in which a Pressure and Temperature element are combined into one package. In this design, the temperature sensor is located in a probe, which is designed to be flush-mounted into the process pipework. This also helps reduce errors due to hydrate formation. For sensors upstream of the Production Master Valve Regulations may however require that there are one or two block valves before the sensor, so, whilst the pressure measurement is unaffected, the temperature measurement may be subject to thermal inertia depending on its location. The two devices are electrically independent, so the connector has to be a four-pin device. Care should be taken, however, to test that both devices are truly independent of each other as regards variations in power supplies on each device and temperature effects.

Figure 22.3 - Combined Pressure / Temperature Transducer

22.5.4 Choke Position (ZT) Most subsea chokes operate on the principle of stepping actuators adjusting the trim via ratchet and pawl mechanisms. Other types operate via a hydraulic motor. All however, require the position of the trim to be accurately monitored from the surface. Positional transducers operate by a variety of mechanisms: a) Potentiometers b) Linear Variable Differential Transformers (LVDT) c) Rotary Variable Differential Transformers (RVDT) d) Magnetic flux gate sensors The simplest is a potentiometer (voltage measuring device), but this involves contact of a moving arm with a resistive material (wire, carbon, etc) which is prone to wear, electrical noise and in the event of a wire-wound potentiometer, discrete steps in the output. Its apparent output can be affected by the resistance of the wiring in the circuit. Some choke manufacturers offer this as standard, being very suitable for topsides use, but requiring the SCM Supplier to provide the necessary interface circuitry, albeit simple. An LVDT or RVDT measures the change in inductance of a coil when an armature is moved into it. This has no contacting parts and is very reliable. Proper electrical design can cancel out the effect of variations in supplied voltage. Again, the SCM supplier must supply the necessary energising voltage and detect the output variations and a special circuit is required.



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The SCM or MCS must then compute the choke position from the LVDT signal. A magnetic fluxgate device is a recent addition to the available techniques. In this, a fixed magnet connected to the rotating part of the choke actuator via a simple shaft causes electronic variations in a sensing circuit. All the electronics are contained within one small can, which can be bolted to the outside of the choke and retrieved if necessary. The output is available in digital or standard 4-20mA form, making interfacing with a SCM straightforward; no further computation within the SCM is required. With all of these sensors, care must be taken to match the available accuracy, hysteresis and resolution to the overall system requirements. If the MCS is simply displaying choke position as a readout, then these are less important. If 'flowrate' is being calculated, whose value will depend on the Cv of the choke (i.e. position) as well as differential pressure across it, then they are of more importance. If the measured position is being used as part of a choke-position control algorithm, in which the choke is moved until the measured position matches the desired position, then all of these are significant (for example, if hysteresis or resolution is too great, the choke might never actually reach the desired position, even when its direction of motion is reversed to attempt to approach it from the other direction, so it could continually 'hunt' for the correct position. Systems that do suffer from this are obliged to put in an 'error-band', of +/- 1%, within which the choke can approach the desired band before its movement is stopped. The system then usually has to provide a means to 'single-step' the choke to allow the Operator to fine-tune its position. 22.5.5 Differential Pressure (DP) A Differential Pressure Sensor is similar to a Pressure Sensor except that pressure is applied on each side of the measuring element; thus, its output is proportional to the difference between the two pressures. The devices are physically similar, as are their electrical connections (4 - 20mA). Care must be taken to match the rating of the device to the expected range to be measured sometimes this is difficult to achieve whilst still providing a device that can withstand the full process pressure across it. 22.5.6 Downhole Pressure/Temperature (DHPTT) 22.5.6.1 General Sensors designed for use down-hole need to be as small and robust as possible, as they are required to operate in extremes of pressure and temperature. In addition, their data is usually required to be very accurate, for use in Well Test calculations. To accomplish this, specialist suppliers of such devices use such mechanisms as quartz crystal gauges or capacitance gauges. The devices usually provide both pressure and temperature information. The cable to the display device also needs to be as simple and as strong as possible, and is usually armoured. The space available within the tubing for the cable from the instrument to the Wellhead is quite small and the cables typically have a single central core and use the armour as the signal return/earth. At the Wellhead, the cabling is continued to the Subsea Control Module, where the data is processed and sent to the MCS via the telemetry link. A single-cored cable presents a number of problems for the interface: any electrical current returning along the cable armouring could cause problems of corrosion, or to the corrosion protection system, if it is connected in such a way as to be in contact with any of the metalwork, or cause a potential difference across any metalwork. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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In addition, as there is more than one parameter to be relayed (as well as the device itself to be powered), the data must be multiplexed in some manner on the core. One technique was to operate the pressure and temperature elements in the sensor using alternately reversing power supply voltage, the current then representing the selected parameter. More recent techniques use a serial datalink, modulating the data onto the power supply. Both methods require a special interface circuit within the SCM, together with correct datahandling protocol in the telemetry system. Most Suppliers have interface cards for the various makes of downhole sensor, but this is an area, which requires definition at the start of a Project to avoid later interface problems. 22.5.6.2 Panex "True Differential Pressure" Transducer Specifications The following is extracted from the data sheet for a typical downhole sensor, as manufactured by the Panex Corporation: Sensor Type:

True Differential

Full Scale Range

10 psi (277 inches of water)

Over-Range Protection

Full static pressure on upstream side

Maximum Static Pressure

15,000 psi

Accuracy

+/-0.1% of full scale (+/- 0.01 psi). Includes linearity, hysteresis and repeatability.

Resolution

0.000036 psi (0.001 inches of water)

Static Pressure Effect

+/- 0.2% of full scale

Temperature Effect

+/- 0.2% of full scale

Maximum Operating Temperature

177 degrees Centigrade

Data Transmission

Frequency Shift. Digital format addressable. Communications, power and data on a single conductor line.

Power

17 to 30 volts DC @ 7 mA.

22.5.7 Sand Detector 22.5.7.1 General Sand monitoring is used during all phases of Oil & Gas production. During the exploration phase, accurate knowledge of sand (solid particle), production is vital to select the most costeffective method for well completion. The sand monitor can help to determine whether there is a problem with the formation; as perforation density can be evaluated, it is possible to gauge the need to gravel pack. Sand monitoring during drill stem testing can provide important background information to enable such decisions to be made. After drilling is completed, sand monitoring will allow the effectiveness of cementing completion and the clean-up procedures to be evaluated. This can prevent costly damage to up-stream filters and other sensitive apparatus. The solids content in production can be measured to determine if gravel packing is required, and allows the effectiveness to be measured. Sand erosion during production can be a significant problem with down-stream equipment, such as valves and chokes being badly damaged in relatively short periods. Significant deposits of sand in the production separators can cause production upsets, with liquid carryover into other equipment. On-line monitoring can significantly assist in controlling these problems, preventing damage and build-up of sand, without greatly affecting production rates. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Detecting sand in the produced fluids can therefore be an important part of a proactive strategy for: •

managing short term damage of vulnerable equipment (e.g. chokes)

•

managing long term damage of pipework

•

warning of reservoir collapse

•

preventing separator level control problems

Sand detectors work either by ‘listening’ to the noise generated by sand impacts on a solid surface (e.g. a bend), or by measuring the erosion damage of a target inserted into the flow. Systems are available from a variety of suppliers, such as (listed in alphabetic order): •

Clamp On

•

Cormon

•

CorrOcean

•

Fluenta

•

Milltronics (Stresswave)

•

Simrad

Acoustic sand probes are available as subsea instruments. As with downhole gauges, the processing of their data requires a specialised interface within the SCM and relevant software treatment. Their suitability for a given application depends on: •

requirements - qualitative or quantitative

•

the flowing conditions

•

the accessibility of the line

•

calibration requirements

•

the availability of an input signal (flowrate)

22.5.7.2 Operation The simplest sensor comprises a thin-walled tube which gives an alarm signal should the production of sand cause significant erosion in the system. However, the sensor must be replaced after it is activated and so is not suitable for subsea use. Non-intrusive acoustic devices are available packaged for subsea use. The Fluenta SAM 400 SR is based on passive acoustic detection of sound created by particles in process flows. The SAM 400 SR uses the signals generated when particles such as sand hit the pipe wall (located downstream of a bend) to detect and quantify particle production. Digital filters and the data processing unit remove flow-generated noise. An algorithm converts the noise generated to a measure of the quantity of sand being produced. A similar device can also be used for Pig Detection (see 22.5.8)



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22.5.7.3 Installation Installation can be carried out topside before deployment, or by ROV. The device is nonintrusive, being clamped onto the production pipework in a suitable location. Power and signals run through an oil-filled hose assembly with ROV connector or similar, using standard twisted-pair cable. Being clamped-on, this design is suitable for retrofitting, providing a 4-20mA interface to an SCM is available. 22.5.8 Pig Detector 22.5.8.1 General Pigging operations such as pipeline cleaning and pipework condition monitoring are dependent on reliable monitoring of the passage of pigs at various points in the system. Conventional detection methods involving devices inserted into the pipeline are liable to cause problems such as pipeline leaks, detector malfunction or pig damage. Pig detection sensors are available, several techniques are used; both are non-intrusive. •

Magnetic Detector

•

Acoustic Detector

22.5.8.2 Magnetic Detectors Magnetic detectors operate by detecting the passage of a magnet located on the Pig. Reed switches in the sensor are closed by the magnetic field and thus can be used to send a signal to the surface. This type of sensor provides a single signal of presence only, with no further information available about pig direction, speed, etc, and must be positioned such that the best magnetic field is obtained from the pig’s magnets. The signal must be ‘latched’ so that a rapid signal due to a fast moving pig is stored until it can be read by the MCS, and de-latched afterwards, either via a ‘reset’ signal or after a time delay. This requires a careful matching of sensitivity vs. latching time vs. system scan cycle time. 22.5.8.3 Acoustic Detectors Acoustic detectors operate by detecting the acoustic energy created by the pig itself as it passes along the pipeline. They are also capable of determining the amount of pipeline debris being pushed ahead by a cleaning pig. Being acoustic, they can reliably detect foam, gel, polyurethane, brush, bi-directional, intelligent and spherical pigs travelling at velocities of 0.05 m/sec and above in oil, gas and multiphase flows.



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23 MATERIALS 23.1 Materials Used The materials used in subsea control systems can vary from basic materials such as carbon steel, to more exotic materials such as 'super duplex' or Titanium, for various reasons such as corrosion resistance, strength, or compatibility. Carbon steel is well understood in terms of material properties, corrosion in seawater, weldability, and cost. Carbon steel is used for weldments and housings for all major subsea components: •

Subsea Control Module Housing

•

Subsea Control Module Mounting Base Frame

•

Umbilical Termination Assembly Housing

•

Subsea Distribution Unit Frame and Housing

•

Subsea Accumulator Module Frames

The material sections are fabricated into frames and housings for containment installation and pulling in. Where materials are designed for containment such as electrical distribution units, they are oil filled and pressure balanced. Therefore, deepwater service does not cause a problem. To slow the rate of corrosion, carbon steel is coated (coating section 23.2). There are some exceptions however, where areas are not coated in small areas where electrical earth bonding is required for electrical connectors, or where a face seal makes up. Hydraulic systems and connectors generally use 316 stainless steel as the main component for its external corrosion resistance, and internal suitability with clean hydraulic systems. Quick-connect / disconnect couplings are assembled from many components requiring different materials. Monel is used for screw nuts to prevent galling, and for coupling selfsealing poppets where a higher strength material is required. Material control is required to eliminate problems with Hydrogen embrittlement. Sometimes Nitronic is used for Quick connect couplings in deepwater applications. Nitronic 60 is used for the female couplings and Nitronic 50 for the male couplings. The Nitronic 50 provides a high strength material and the difference in hardness between the 60 and 50 grades provides anti-galling properties. Springs have to be from a material with permanent spring properties that does not corrode. Hastelloy is often used for this service, and Elgiloy is now being used. The O-Ring seals for the female halves of the hydraulic quick connect / disconnect coupling need to be compatible with the hydraulic or chemical fluid used and with seawater. Seals are made from materials such as Nitrile, or Viton for hydraulic service, and Chemraz, Fluortrell or Isolast for severe service such as chemicals. Backup seals to prevent O-Ring extrusion can be of Teflon or Peek. For metal seal couplings, seal material such as Inconel 750 gold plated is used. Piece parts such as the SCMMB interface, the SCM base and mating stab plate assemblies are all machined from 316 stainless steel. Electrical Connectors are usually made using 316 stainless-steel bodies (TotalFina standard is super-duplex e.g. Ferralium SD40 or Zeron 100) with water blocks of Ultem and the conductive pins of gold plated copper. The pressure compensation diaphragms and the boot seals for the cables are made from neoprene or synthetic rubber. The pressure containment fluid is silicon based dielectric oil. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The directional control valves (DCVs) within the control modules are made from 316 stainless steel bodies, with internals to seal with metal to metal shear seal action, and also to provide sufficient wear capabilities. In deepwater applications, seawater has migrated into valves causing corrosion problems and a new generation of valves with seawater tolerant internals such as Inconel, MP35N, and ceramics being used. The electronics assembly within the subsea control module is contained in a one-atmosphere housing called a SEM housing. The SEM housings were always made of Aluminium for lightness. For deepwater applications where greater strength is required to prevent the housing collapsing, high strength steel or aviation strength aluminium is used. Transducers are made from materials to suit interfaces. Choke position indicators housings are made from 316 stainless steel, pressure transducers which interface with Xmas tree flanges, ring grooves and gaskets are generally made from duplex stainless steel.

23.2 Coating The noble materials such as stainless steel and Monel do not need coating. Neither does Duplex stainless steel, although it often is coated to reduce the un-coated surface area used in calculations of the amount of anodes for surface protection. Carbon Steel is coated with a multi-coat epoxy designed for permanent use underwater. The coating of carbon steel is time-consuming, taking several days to apply the coatings, but has the advantage that high-visibility colours, such as white and yellow, can be used.

23.3 Cathodic Protection Zinc Alloy anodes are used in a sacrificial mode to protect the subsea structures. The number of anodes required is based on the initial un-coated surface area plus the estimated area that becomes un-coated during the field life.

Figure 23.1 - Electrical Connectors Earth Bonded to SCMMB Suppliers providing Cathodic protection for their own equipment in isolation, and lack of system engineering has led to an over-protection of subsea facilities with its own problems. This has led to a change in philosophy so that subsea control equipment is protected under the main structure e.g. an Xmas tree by earth bonding to the main structure Cathodic protection system. This provides the benefit during installation in deepwater of equipment such as subsea control modules. SCMs without sacrificial anodes attached are lighter and do not have additional protrusions that could prevent easy installation.



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23.4 Galvanic Action Galvanic Cells between different materials in seawater can cause corrosion and pitting between materials. In a similar manner to the electrical cell set up allowing the Zinc Alloy anode to sacrifice by design to protect the more noble Cathode, dissimilar materials in contact or close proximity can also set up a cell and one material will corrode. It is a very important design consideration that should not be over-looked, and those materials in close proximity have similar potential differences in seawater.



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24 MARKINGS 24.1 Equipment Marking Subsea control system deliverables are delivered as individual items and to different locations. Each part has a Manufacturer's part number and a serial number. The part number identifies the assembly through the manufacturing process and for re-ordering, and the serial number gives unique traceability through the assembly and testing, and for material traceability. This provides a formal and acceptable method of tracking part numbers back to the design documents, and for installation on Xmas trees, manifolds, etc. In addition to the Manufacturer's own identification system, each unit in the system will also have an Equipment Number, allocated by the Customer or overall Contractor, which enables all Platform and Subsea equipment to be identified for overall control of the offshore installation.

Figure 24.1 - Identification Plates In addition, all subsea valves and instruments are usually allocated a Tag Number, which identifies their function and, again, enables them to be identified on an overall offshore installation database and on the overall P&ID. It is important to define Equipment and Tag Numbers at an early stage in the project to ensure all items and drawings use the same information, to avoid confusion. Furthermore, hydraulic and electrical signals used throughout the system are usually identified by the Manufacturer as part of its own overall System Block Diagram, to uniquely identify each signal throughout the system For example, LPA, LPB, HPA, HPB to identify low/high pressure dual-redundant channels. Where equipment such as the subsea control module mounting base (SCMMB) requires hooking up to the Xmas tree actuator tubing by third-party installation contractors or manufacturers, the hydraulic connections will have hydraulic interface connections stamped onto the connection plate.



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24.2 Subsea Marking General When subsea controls equipment is to be hooked up subsea, there is a need for clearly visible markings, which can be identified by the video camera from the ROV. Equipment such as subsea control modules (SCMs) need clear identification of the service (e.g. Production, Water Injection), the module address or module addresses for dual SEMs to set up the subsea communications, and the front face for orientation purposes, plus details such as the weight.

Figure 24.2 - Stencil Painted Markers Module mounting bases need identification of the orientation for installation on the Xmas tree or manifold structure, and identification of the connection faceplate for hook up by the ROV. Subsea Distribution Units require identification of the hydraulic and electrical connections for jumper hook up, as they are routed to a large number of SCMs. Any manual valves also need to be identified with their service and open and closed directions. Block and bleed valves are usually identified by colour coding on the handle and/or by the shape of the handle itself. Jumpers require identification of the jumper service, and the connecting interface. This helps with planning installation so that the jumpers can be laid out on the installation pallet for deployment and hook up. Such identification markings need to be located at least at each end of the jumper and at least once along the length.

Figure 24.3 - Cable Markers



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24.3 Marking Methods An easy method of identification is to paint fixed items, such as the SCMMB, white and removable items, such as the SCM, yellow. Xmas tree manufacturers often paint using a different paint specification and a pale yellow. By using yellow or white paint to give high visibility subsea of structural items, it is easy to provide stencilling onto the painted surfaces with the contrasting colour black.

Figure 24.4 - Colour Keyed Identification These labels will be covered in marine growth in time, that must be brushed or jetted away when returning to the site for intervention. There are also subsea markers available with anti foul properties to inhibit marine growth, although the use of these is sometimes restricted for environmental reasons. Jumper hoses and cables are marked with cable markers with black lettering on a yellow background. These are fixed to the jumper at each end with cable ties. To ensure that these markers do not detach due to snagging during handling a clear heat shrink sleeve is applied over the marker. They need to be large enough to ensure clear visibility.



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25 QUALITY 25.1 Introduction Early subsea control systems were born with the concept that Aerospace Quality was essential for design and build of equipment for subsea applications. Aerospace hydraulic valves were used for control functions, hydraulic systems were flushed to Aerospace Standards, and electronic components used were Military (MIL) Specification. Dual Systems were used to eliminate single point failure. Components were subjected to Qualification Testing. This requirement was for life cycle testing of valves for wear, leakage, and failure. Pressure Testing of components and housings at pressures usually double working depth, burn in and cycling electronics for temperature, shock and vibration. Testing hydraulic connectors for make up and leakage, testing of electrical connectors for make up, continuity and Insulation Resistance. Material compatibility was (and still is) a major issue. This can be due to electrical cells between different metals in seawater, compatibility of seals in valves or hydraulic connectors, or compensation bladders with hydraulic oils, dielectric oils, or chemicals. Hydraulic tube connections were welded for Integrity. Weld Procedures and Welder Qualifications are necessary for maintaining integrity in systems. Where welds are in seawater the welds are over alloyed to provide a more noble material in the weld and heat affected zone. There was a great step change in policy and thinking from the requirements for the Oil Patch to the requirements of subsea technology. The change was brought about due to the high cost of failure for intervention, paralleled to the disastrous results of similar failures in the aerospace industry. Modern Quality Assurance techniques and procedures have been refined from the original aerospace applications and are now accepted as standard in the subsea industry.

25.2 Quality Planning Planning quality is paramount in aiding the purchaser to achieve the criteria that has been prescribed within the contract and associated documentation with the ISO 9001 Standard being the foundation, covering all areas from contract review to delivery of the completed product or service. Experience over the years has revealed that quality has to be built into the contract at the onset, and typically, mandatory documentation deliverables for purchaser approval would be: 25.2.1 Project Quality Plan (Project Management Plan) To gain assurance that all contract activities will be identified, implemented, and controlled effectively throughout the contract duration. 25.2.2 Design Plan To identify and control design input from the purchaser and design output from the supplier. Taking into account the design basis, qualification and verification activities, and allowing intervention points within the plan for purchaser / third party / certifying authority activities as applicable.



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25.2.3 Inspection and Test Plan The inspection and test plan (ITP) controls all areas such as contract review, purchasing, sub-suppliers, goods inwards, manufacturing process control, and quality control through to final inspection. The ITP highlights the procedures to be utilised that define the prescribed acceptance procedure. The ITP also contains the intervention points for purchaser / third party / certification.

25.3 Manufacture Following on from qualification testing, and demonstrating the reliability of system components (some of them prototypes), there is the requirement to manufacture in production quantities. Hydraulic components are commonly manufactured in materials that are usually difficult to machine, to high tolerances. The requirement to miniaturise components in order to make control modules smaller and easier to handle and install in deep water has necessitated tighter tolerances and less room for error. Gun Drilling is necessary for long hydraulic galleries, Cross drilling often leaves burrs at the point of intersection, which have to be removed by laser de-burring and ultrasonic techniques.

25.4 Testing Production testing of components, sub-assemblies, assemblies, and the system is necessary to maintain quality and to ensure that the system will perform after installation to the design criteria. Factory Acceptance Testing (FAT) is fully covered in Section 27. 25.5 Inspection A Supplier's Quality Assurance system (in conjunction with the allocated Project Manager) will normally provide the control and documentation of all of the above aspects. However, the Customer is recommended to mobilise its own inspectors to follow all stages of a subsea control system contract in order to fully assure itself that each component is correctly manufactured and tested. This also ensures the eventual data books delivered with the system have already been witnessed by the Customer's representatives and avoids lastminute delays due to uncertainty about any individual item.

25.6 Conclusion The manufacture, testing, and long-term reliability of components and subsea systems is facilitated by the application of the Quality Management System requirements of ISO 9001. However, these systems are very complex with many components, sub-assemblies and interfaces. Quality Objectives can only be achieved in practice by effective Project Management and Control, with the emphasis on Management. This has been recognised by the standards authority and the Current International Standard ISO 9001: 1994, is to be revised and expected to be Issued by the end of year 2000. The salient change will be to incorporate 'The Management of the Project Process’.



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26 RUNNING TOOLS 26.1 Requirement When running subsea equipment in deepwater, a running tool is required due to the size and weight of the equipment, the forces required to force the mating parts together, and to latch the equipment in place. A major component such as the subsea control module requires such a running tool. This can be a simple relatively low cost purpose built running tool for one particular application, or a more complex and expensive tool called a Multi Mode Running Tool (MMRT). An MMRT can run and retrieve subsea control modules and subsea accumulator modules, and can also be designed and used for other activities such as running and retrieving subsea chokes, multiphase flow meters, etc. A large work class ROV is required for this activity.

26.2 Minimum Fit Running Tool (MFRT) The single purpose built minimum fit running tool is not described, as it is project specific.

26.3 Multi Mode Running Tool (MMRT) The multi mode running tool can be deployed on a lift wire from a surface winch or ROV. A control system is required which can be a direct hydraulic from the surface or through an ROV hydraulic and electrical stab system. For more complex applications, control can be onboard local control with power and data through a discrete electrical umbilical or through the ROV umbilical. In lift wire mode and using guide wires, the running tool is lowered using a heave compensated winch onto the API 17H interface. The running tool will have a soft landing device to protect the SCM from shock damage. The running tool is heavy in water. The running tool uncouples the SCM or SAM and retrieves it to the surface. The component is exchanged at the surface, re-deployed to the subsea interface, and reinstalled. When deployed by ROV, the MMRT, the ROV, and the component have to be neutrally buoyant in water. The tool uses transfer weights of equivalent weight to the SCM or SAM to be recovered, and has buoyancy added to balance the weight requirements. The ROV deploys to the interface, retrieves the SCM or SAM, and leaves the transfer weights in the vertical tubes of the interface, and the SCM or SAM is retrieved to the surface. The component is exchanged at the surface, re-deployed to the subsea interface, and reinstalled. The transfer weights are recovered before the ROV is retrieved.



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Figure 26.1 - MMRT with ROV Alternatively, to eliminate a trip to the surface by the ROV, the MMRT can be lowered to the seabed in a cage that carries the new replacement component and a second set of transfer weights. The ROV docks onto the MMRT, and guide it onto the interface of the component to be replaced. The SCM or SAM is retrieved by the tool, and the transfer weights are left at the interface. The ROV moves to the cage and deposits the SCM or SAM in bay 1 of the cage, and then picks up the second set of transfer weights. The ROV then moves to bay 2, picks up the replacement component and deposits the second set of transfer weights. The ROV moves back to the job, docks at the interface and installs the replacement component. The ROV then retrieves the first set of transfer weights back to the cage.

26.4 Single Wire Deployment. An SCM or SAM can be deployed using a single guide wire. The guide wire needs a winch with a lift and lock tool, and a high quality heave compensation mechanism to prevent damage to the SCM on landing. The SCM or SAM is lowered into a guide funnel as directed by the ROV, an orientation helix or location spigot(s) may be used to orientate the SCM correctly onto the mounting base. The deployment wire is uncoupled and the ROV latches the SCM onto the mounting base. This method of deployment dispenses with the MMRT, but a mechanism is still required to exert down force and to mate and latch the SCM onto the SCMMB.

26.5 Drill String Deployment When a drilling rig is on station, it is possible that there could be a preference to run an SCM using a drill string. This is not a preferred and controlled method from an engineering viewpoint, but this method has been used in the past.



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27 FACTORY ACCEPTANCE TESTING (FAT) 27.1 General Every deliverable component of the Subsea Control System should be subjected to a formal test procedure, before acceptance from the Supplier for shipment to the delivery location. This type of test is usually termed a ‘Factory Acceptance Test’ or ‘FAT’. The proposed test procedure should be written and submitted to the Purchaser for review and approval. No test should be performed until the document has reached an acceptable status; therefore, the first issue should be submitted to the Purchaser at least 6 weeks before the test. A signed, approved copy of the test procedure should be used to perform the test and the test procedure should not then be modified without written permission from the Purchaser; in any event, a corrected document should be issued. The Purchaser or its Engineering Representative should witness every FAT. Sole QC is inadequate for this Engineering function which requires knowledge and understanding of the system and system components to observe the system test and to note and question any irregularities. In order to achieve this, the Supplier must issue a Notice Of Readiness in sufficient time for the Purchaser to mobilise its Representative, typically, 5 working days is required. Care should therefore be taken in contractual documentation at the start of a project to ensure these provisions are included, else the Purchaser will find that the last minute changes of schedule and lack of readiness will cause considerable disruption to its other project responsibilities. Similarly, where some tests require the presence of equipment supplied by others, care should be taken to ensure the schedules coincide. 27.2 Test Requirements In general, equipment should be tested for: •

Mechanical completion and conformance to drawing dimensions.

•

Interfaces with other equipment.

•

Functional operation over the complete range of specified parameters.

Of particular concern should be Hyperbaric testing, particularly in deepwater applications where equipment has not previously been fully qualified for the design working pressure. All subsea equipment must be tested inside a hyperbaric chamber and be surrounded by the test medium. This is not always easy to achieve; equipment is sometimes tested at modular level and later connected together and care should be taken to ensure that there does not remain an interface that has never been subjected to hyperbaric pressure. Each item of equipment should be tested using Simulators for inputs and test boxes for outputs. It is inadvisable to test one unit using another, deliverable, unit as a source of inputs or outputs, as this does not then independently verify the correct function of these inputs/outputs. Testing against other deliverable items is done at a later stage (see "System Integration Testing" section 28). It is also advisable to perform 'low-level' testing on complex items, such as the subsea telemetry protocol, using the Supplier's Design Specifications, on at least the first deliverable unit, to verify that all sub-units are operating correctly and, in particular, perform correctly with applied 'fault' conditions. Care should be taken that the Simulators have themselves previously been tested as both functional and fully-representative of the unit they are simulating. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Other environmental testing should also be performed on at least one of every design of deliverable equipment. This should include vibration and shock testing, load tests. This "Qualification Testing" may form a separate part of the overall QA Plan and Contract; it should only be granted a 'waiver' if the Supplier can demonstrate similar testing on identical equipment from an earlier project. 27.3 Documentation Before commencing the test, ensure that the latest, Customer-approved version of the Test procedure is to be used. Verify that the item to be tested has been correctly manufactured in accordance with the Suppliers normal manufacturing procedures and documentation and is fully complete. The results of the FAT procedure should be recorded in a Factory Acceptance Test Report document, usually included as an Appendix to the FAT procedure itself. The Report document should then be supplied with the Unit and in any event, it should form part of the final project documentation. It should be signed and dated by all witnessing parties. The report should be written as concisely as possible, however, care should be taken that actual test values are recorded, as well as a statement of PASS/FAIL for each test, so that the document can be used to check differences between identical units, as evidence of drift in parameters, or be used as reference values for other future tests. All tests should be witnessed by the Supplier's QA department and test results 'stamped' as official records of events. Ideally, the Supplier should have performed each type of test procedure at least once, before notifying the Purchaser to attend, so that errors in the procedure are detected at an early stage. Parameters appearing outside of the specified test limits are cause for rejection of the complete unit; a re-test should only be held once the problem has been found, corrected, and a report made to, and accepted by the Purchaser. This is then an incentive for a 'dry-run' test to be performed by the Supplier before notifying the Purchaser. If so included in the Contract, a Purchaser may be entitled to reclaim its costs of attendance following an aborted test, unless due to unforeseen events. 27.4 Test Parameters The following is a summary of parameters that should be tested as a minimum for each type of subsea control system component described in this Chapter of the Data Book. It cannot be exhaustive, as each system will be different, but the Purchaser will find that the more testing that can be performed at the factory, or onshore before installation, the better the chances of a trouble-free installation and commissioning. 27.4.1 Master Control Station

• • • • • •

All mechanical Details; all components/serial numbers recorded. Operation over power supply range. All memory passes functional test. Operating software installed onto newly formatted / de-fragmented hard disc. Start up (and shutdown) operates smoothly and does not cause fluctuations in digital or serial outputs. All displays match the design specification.



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• • • • • • • • •

•

• •


Each display to be tested for correct system operation (e.g. EPU display shows all necessary EPU/HPU parameters, can control all outputs etc, all maintenance displays operational, 'help' files correctly installed.) All ESD inputs cause the correct ESD sequence. Interfaces to Platform SCADA system operate correctly. Date/time synchronisation with PCS. Subsea Telemetry matches its design specification, operates correctly with a 'real' SCM, can detect all types of fault without loss of data to other operational SCMs. (Test equipment should simulate a complete field, rather than just one SCM). All interlocks and overrides operate correctly and do not cause unexpected actions when released. MCS operates correctly when 'fully-loaded' i.e. with a full subsea system attached, interface to SCADA operational, ESD inputs activated. MCS operates correctly when some of the subsea SCMs are inoperative (faulty or removed). Of particular interest in testing an MCS is its ability to handle 'unexpected' events, such as particular failure modes in the subsea telemetry, error-codes in the various serial interfaces, unexpected key-presses during other operations, activation of a higher-priority ESD signal during a lower-priority one etc. Where a dual-redundant system is employed, the changeover to the backup unit is 'bumpless' i.e. does not cause any unexpected actions, changes of state of digital outputs, operation of any subsea valves etc. Similarly, the return to the main unit should also be 'bumpless'. Historical data recording system operates correctly over a wide time period. Verify data can be downloaded to disc/ other equipment as per specification. Operates correctly over full range of ambient temperature. A 'heat-soak' test should be performed.

27.4.2 Electric Power Unit • Operation over full range of input voltage, frequency, loads, start up surges. • Visual checks on workmanship, cable marking etc. • Insulation testing cores to ground and each other. • Continuity testing. • Earth continuity tests. • Circuit breaker tests. • Line Insulation monitoring tests (particularly as regards usage with subsea umbilicals and long-term Testing) • Heat soak tests / Burn in period. 27.4.3 Uninterruptible Power Supply

• • • • • • •

Operation over full range of input voltage, frequency, loads, start up surges. Heat soak tests / Burn in period. Visual checks on workmanship, cable marking etc. Insulation testing cores to ground and each other. Continuity testing. Earth continuity tests. Circuit breaker tests.



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27.4.4 Hydraulic Power Unit • Mechanical details correct, including correct identification of all hand valves, gauges etc per P&ID. • Certified lift tests performed on pad-eyes. • Correct pre-charge in accumulators. • Correct operation of safety valves. • Correct generation of output pressures. • ESD solenoid valve operation. • Adjustment of output pressures (where regulators available). • All electrical system operational, including all outputs to remote display at MCS (may be a serial data link), emergency stop circuits, remote/local control of pumps, flowmeters. 27.4.5 Subsea Control Module and Mounting Base • Correct mechanical details • Correct interface with stabplates, connectors (correctly polarised and marked), Mounting Base. • Telemetry system operating as per design specification; test all electronic commands for correct operation on at least the first unit. • Hydraulic outputs operate correctly; maintain output until LP supply lowered to specified value and then all close. • No hydraulic leakage to vent port • No outputs affect other outputs when operated. • All sensor inputs operate correctly and are calibrated correctly. • Heat soak test (at high and low temperatures) • Hyperbaric test on each unit. 27.4.6 Subsea Accumulator Module • All mechanical details correct as per specification • Correct pre-charge in accumulators • All valves operate correctly, marked correctly. • Pressure and volume test. 27.4.7 Subsea Distribution Unit • All mechanical details correct as per specification. Markings correct and visible. • Correct interface with stabplates, connectors (correctly polarised and marked), Mounting Base, ROV connectors, • All block/bleed valves operate correctly; no leaks • All electrical outputs operate correctly and wired correctly. • Current limit functions operate correctly, where included. • Hyperbaric test on each unit. This is usually impossible on the whole unit due to its size, however, where an SDU contains an electrical distribution unit (EDU), this is usually small enough to be Hyperbarically tested, and this should be insisted upon.



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27.4.8 Subsea Umbilical Termination Unit • All mechanical details correct as per specification. Markings correct and visible. • Hyperbaric testing is usually impossible on these units due to their size. However, pressure testing of field-installable electrical connectors must be performed as a minimum. 27.4.9 Topsides Umbilical Termination Unit • All mechanical details correct as per specification. • Markings correct and visible. • Pressure & leak test all pipes and valves • Lift test 27.4.10 Transducers 27.4.10.1 General • All transducers should be hyperbarically tested, complete with any third-party electrical cable harness. • Each transducer should be calibration tested. The serial number should be noted and a certificate should accompany each unit. Care should be taken to track where each sensor is eventually installed subsea. Transducers that require the MCS to perform calculations to obtain the final value will be supplied with calibration coefficients. Again, these must be tracked with each unit. • Hysteresis test • Speed of response test • Test for correct operation over full range of supply voltage. • Test for correct operation over full range of temperature. • Mechanical verification, particularly of interface flange / fittings. 27.4.10.2 Combined Pressure/temperature In addition to the general test requirements, the following are required:

•

Tests should be performed to verify that changes in one channel do not affect the other, particularly when operating at the minimum supply voltage.

27.4.10.3 Choke Position In addition to the general test requirements, the following are required:

•

Verify the amount of hysteresis when choke moves in open direction then back to closed again - this can have significant effect if the subsea system is to operate in a 'closed-loop' mode where the system moves the choke until the sensor displays the correct value. If the sensor exhibits significant hysteresis, the system may continuously 'hunt' the correct position but never achieve it.



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27.4.10.4 Downhole Pressure/temperature In addition to the general test requirements, the following are required:

• • •

The devices may be accompanied by the calibration coefficients referred to above. Where a device has a serial data link interface to the SCM, this interface should be tested for correct operation in ALL modes and over the complete supply voltage range and temperature. Care should be taken to verify that the correct earthing philosophy has been followed; there is a risk of introducing severe corrosion if this has not been followed correctly, particularly when the device is connected to the SCM; there are several connections between the downhole device and SCM, any of which could introduce an earth-loop if not correctly wired.

27.4.10.5 Sand Detector In addition to the general test requirements, the following are required:

•

Ensure the sand-detection signal operates correctly per design specification, particularly when later connected to the SCM/MCS.

27.4.10.6 Pig Detector In addition to the general test requirements, the following are required:

• •

Verify correct operation of the device over the specified range of 'pig' velocities. Ensure the 'latching' of the 'detect' signal operates correctly per design specification, particularly when later connected to the SCM.

27.4.11 Weak Link In addition to the general test requirements, the following are required:

• •

•

Where the device is a destructive, guillotine-type mechanism, ensure it can cleanly cut a fully populated set of cables/hoses. Where the device is a self-contained disconnection device, ensure it cleanly disconnects without hydraulic leakage. One side of the device may be specified to vent hydraulic fluid, ensure this operates correctly. Electrical connectors must also operate without causing line-insulation faults or short-circuits. Verification of shear-pin type testing.



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28 SYSTEM INTEGRATION TESTING (SIT) 28.1 General Every deliverable component of the Subsea Control System should be tested together as a system with all other deliverable items from the same Supplier, and if possible, with all other items to which they will be attached when eventually installed subsea. This type of test is usually termed a ‘System Integration Test’ or ‘SIT’. However, if the test is restricted to equipment from the one Supplier (Controls) then it is sometimes referred to as a 'Final Factory Acceptance Test' (FFAT) to distinguish it from a later test with the rest of the subsea equipment. Effort should be made to ensure the availability in the project Schedule for access to at least one subsea Xmas tree and the template / manifold, so that the overall operation of the system can be verified. These are not always available at the correct time for 'acceptance testing' of the subsea controls equipment. The controls contract should therefore clearly state the definition of any required system testing and should clarify at what point the equipment is considered 'accepted' from the Supplier. Ideally, this should only be when overall operation of the complete system (including trees, manifold etc) is proven, but this is often difficult to arrange, particularly if the individual schedules are widely separated. In this event, a financial retention is sometimes made, to ensure the eventual testing is performed. In any event, a Warranty Period will cover problems with system operation, but the incentive to correct them in a timely manner must be maintained. A Client will sometimes place high importance on testing a Xmas tree with the subsea system. This is also a form of Integration Test, but it should be noted that this does not test the full operation of the system, particularly if the system will normally operate more than one tree and/or a manifold or template. There is only limited value in testing a tree with more than just the SCM, as there is little difference between this test and an FAT of the SCM, or of the Tree itself. The SIT is intended to test the system in a 'fully-loaded' condition, where more than one unit is involved. The Client or its Representative should witness the SIT. In order to achieve this, the Supplier must issue a Notice Of Readiness in sufficient time for the Client to mobilise its Representatives, typically, 10-15 working days is required to mobilise all interested parties for an SIT. Care should therefore be taken in contractual documentation at the start of a project to ensure these provisions are included, else the Client will find that the last minute changes of schedule and lack of readiness will cause considerable disruption to its other project responsibilities. Similarly, where some tests require the presence of equipment supplied by others, care should be taken to ensure the schedules coincide. The SIT is the only opportunity for a Client, its partners, the eventual system Operators and the Installation Contractor, to see all the equipment operating as it should, prior to being installed subsea. Therefore, significant importance should be placed on the event and the witnessing thereof. Photographs and video records of all aspects of the equipment should be made. All drawings should be checked and marked-up for 'as-built' at this time, as full and correct records will be invaluable once installation commences and for the life of the system. ROV operators in particular should use the opportunity to familiarise their operators with the equipment. An SIT is usually performed at the manifold / template fabricator's site, or tree supplier, and provision must be made in the respective contracts for access by the controls supplier etc to perform these tests without disruption to the formers' contractual schedule.



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28.2 Test Requirements At the start of SIT, it is assumed that all equipment has already been subjected to Factory Acceptance Testing (FAT) (the availability of the Test Records should be verified). Therefore, each item can be assumed to operate correctly and interface with its immediate external interfaces. The emphasis of the SIT is therefore to verify that the overall system operates as expected, in particular with equipment that has never been connected together as a system before. In particular, that the equipment interfaces correctly with its Installation aids and can be physically installed into position, retrieved, operated by ROV etc. In general, equipment should be tested for: •

Mechanical completion and conformance to drawing dimensions.

•

Interfaces with other equipment.

•

Functional operation over the complete range of specified parameters.

Where equipment is missing from the SIT, Simulators should be employed; care should be taken that these have themselves previously been tested as both functional and fully representative of the unit they are simulating.

28.3 Documentation The proposed test procedure should be written and submitted to the Client for review and approval. No test should be performed until the document has reached an acceptable status; therefore, the first issue should be submitted to the Client at least 6 weeks before the test. A signed, approved copy of the test procedure should be used to perform the test and the test procedure should not then be modified without written permission from the Client; in any event, a corrected document should be issued. Previous FAT Results should be available. The results of the SIT procedure should be recorded in a System Acceptance Test Report document, usually included as an Appendix to the SIT procedure itself. The Report document should then be supplied with the final project documentation. It should be signed and dated by all witnessing parties. The report should be written as concisely as possible. However, care should be taken that actual test values are recorded, as well as a statement of PASS/FAIL for each test, so that the document can be used to check differences between identical units, as evidence of drift in parameters, or be used as reference values for other future tests. All tests should be witnessed by the Supplier's QA department and test results 'stamped' as official records of events. Ideally, the Supplier should have performed each test procedure at least once, before notifying the Client to attend, so that errors in the procedure are detected at an early stage.



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28.4 Test Parameters The following is a summary of parameters that should be tested as a minimum for a subsea control system. It cannot be exhaustive, as each system will be different, but the Client will find that the more testing that can be performed onshore before installation, the better the chances of a trouble-free installation and commissioning.

• • • • • • • •

• • • • • • • • • • • • • •

Installation and retrieval of subsea equipment using Running Tools / Installation Frames etc. Operation of controls & valves using ROV / accessibility by Divers. System start up from 'cold' i.e. not pressurised, electrical power off Time to pressurise the system should be recorded, and volume of fluid. No hydraulic leaks throughout the system. All manual valves set to correct positions. MCS correctly displays status of all sensors, valves, subsidiary equipment (HPU, EPU). Preferably pressurise process pipework to enable operation of all pressure sensors to be verified - this is particularly important where they have been already installed for some time on the Manifold / template and subjected to other pipework testing by third-parties). Check temperature transducers show nominal ambient readings. All SCM internal parameters correct (voltages, pressures, telemetry system) operational and within expected limits, for all loads from minimum to maximum. Interface with SCADA operating correctly. System can operate every valve and choke without affecting any other valve. Times to open/close valves and chokes should be recorded; volumes of fluid required. No other valves move when a valve is operated. Behaviour of system without Subsea Accumulator Module operational. System correctly performs ESD sequences. Times to perform ESD sequences should be recorded. System behaves correctly for wells on 'Workover'. Historical Database / Trends operate correctly. Behaviour of system on failure of one or more power/signal channels, failure of one unit in dual-redundant system (MCS, HPU outputs). Determine limits of operation of system with reduced power supply voltage, reduced system pressures. Verify operation of deliverable test equipment (particularly telemetry monitoring devices). Verify interchangeability of identical components (SCM - ability to easily change Module Address without causing unexpected system problems. Sensors - ability to alter calibration coefficients).



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28.5 Post-SIT checks On completion of the SIT, particular attention should be paid to leaving the system in the correct state for installation and / or operation, such as:

• • • • •

All manual valves set to correct position for installation and/or operation. All sensor block valves set to correct position (usually 'open'). All alarm limits returned to nominal values (for process parameters) or to correct value for subsea system equipment as specified by the Supplier (HPU, EPU, SCM). Equipment re-packed in offshore transport crates (sealed, protected) if not being immediately installed. No equipment left on manifold / template unless scheduled for installation with it if so, all hydraulic & electrical connectors to be fixed on their 'parking' plates or suitably protected/greased/fixed down.



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29 ALTERNATIVE CONTROL SYSTEMS 29.1 Introduction The primary factors affecting the control system design are the Field architecture and offset distances (refer to section 7), and for most cases, an electro-hydraulic multiplexed control system is suitable. However, the offset distance from the subsea production equipment to the host facility platform or the onshore facility may dictate that other solutions are considered. The installed cost of a long or complex composite electro-hydraulic umbilical carrying power and signal cables, hoses for low pressure and high pressure hydraulic systems, and the additional chemical injection hose requirement for services such as corrosion inhibitor, scale inhibitor, wax inhibitor, or methanol for start up, can significantly reduce the overall field economics. There are two options for eliminating long length umbilicals in this situation. They are: •

buoy based systems where all of the control requirements are located at the surface.

•

autonomous subsea systems where all of the control requirements are located on the seabed.

29.2 Buoy Based Control Systems The buoy concept has been around for many years. The concept is that all of the control requirements are installed onto a buoy which is moored above the subsea facilities and which carries all of the control requirements. An umbilical from the buoy to the seabed facilities transports all of the required functions. The original concepts for such buoys proposed low-cost flat-bed barge designs, but later concepts and the buoys that have since been installed have been substantial ‘spar’ type designs. The ‘spars’ have a large draft below their surface to provide stability. These are unmanned facilities but there is a requirement for warning lamps and for radar reflectors for positioning requirements. The buoy has to carry the hydraulic power unit (HPU) and Electrical Power Unit (EPU) for the subsea control system, and chemical injection pumps and reservoirs for the injection requirements. Control has to be by a dual high-integrity, secure radio link. Electrical Switchgear is required for motor starters, and for lighting circuits and safety requirements. There is also a requirement for power generation. A dual system is required for redundancy and batteries are required for back up. Storage facilities are required for fluids. Tanks are required for hydraulic fluid, injection chemicals, and diesel for the power generation. As these are unmanned facilities, the size of the storage tanks may well become substantial. The designer has to make a case for the periods between bunkering of fluids. If the storage amounts are minimised, it is essential that all-year-round supply boat access is available in order to prevent unplanned shutdowns. One spar buoy design has such a deep draft that elevators are required to transport personnel and equipment between decks. The fabrication of such buoys is done in such a way that equipment skids are installed onto the decks during fabrication. It is essential, however, that major items, such as pumps, can be retrieved and replaced if necessary, so modular design of equipment is required. The buoy has to be secured to the seabed using anchors or piles, or a combination of both. There has to be a means of connecting and disconnecting the control umbilical. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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A major issue is personnel safety. Maintenance personnel need to be able to safely get on and off the buoy for maintenance and bunkering of utility fluids. There is a need for air-handling systems, fire-detection systems and fire dampers, emergency access ways, etc. In addition, there is a need for food and fresh water, and temporary accommodation in case it is not possible to get off the buoy due to bad weather.

Figure 29.1 – East Spar Buoy

29.3 Autonomous Subsea Systems 29.3.1 Introduction To dispense with the subsea umbilical there is a requirement for electrical supply, hydraulic power supplies, solenoid valves, control and monitoring, and acoustic communications – all subsea. These are the elements of the autonomous control system. Whilst electricity can be stored in batteries (and some battery storage is always necessary), there is the requirement for subsea power generation. The batteries need to be sized to withstand production and planned annual shutdown requirements, and to be able to supply a peak load for start up requirements. Battery technology is continually improving and an optimum battery can be selected at the time of use. The criteria for battery selection are minimum gas production, minimum maintenance, reliable battery performance, final voltage as high as possible, and capability for partial charge and discharge.



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29.3.2 Power Generation A turbo-generator could be used for a dry gas service using a bypass loop from the main production flowline, or from a gas lift pipeline if used. As with all rotating equipment, there is a reliability consideration in that the sealed bearings would have to meet the equipment design life without additional lubrication, and that the electrics would need to be segregated from the gas source. The rotating speed must be governed to limit the axial thrust on the bearings. Where produced fluids such as oil, water, and gas condensate are to be considered, the reliability of the turbo-generator has to be questioned. An alternative is thermo-electric power generation. Thermo-electric power generation is based on the ‘Seebeck Effect’. When the junctions of two dissimilar metals (semi-conductors) are maintained at different temperatures, a potential difference is created which produces a flow of electrical current in a circuit. (In submarines the reverse ‘Peltier Effect’ is utilised to develop silent cooling systems). The design of such a device needs to consider the best interface material between the thermo-electric elements and the hot and cold plates, and take into account the seawater conditions. The selection has to be compatible with seawater for long term use and reliability. The reliability over the turbo-generator is greatly enhanced, as there are no moving parts. The thermo-electric elements are arranged externally around a pipe spool, and are therefore non intrusive. The elements must be sized to provide an output to meet the design specification. The heat flux from the pipe spool source to the cold seawater can be optimised by using cooling fins on the external plate and increasing the exposed surface area. The spool can also be installed in a vertical plane to promote convection currents. A copper alloy cover can be used to enhance the thermal transfer as well as inhibiting marine growth. 29.3.3 Subsea Control System The control system is packaged into a module to include the Hydraulic Power Unit (HPU), Power Conditioner System, Motor Control System, Subsea Electronics Module (SEM), and solenoid control valves. The HPU provides the hydraulic fluid power to the valve control system. It includes the reservoir, pumps, motors, accumulators, and filters in a dual configuration. Well control usually requires Low Pressure and High Pressure systems, but HP can be generated from LP using intensifiers. As the reservoir cannot be replenished without intervention, closed hydraulic systems must be used for this application. The Power Conditioner System provides the interfaces between the generated electrical power, the electronics, and the batteries. It provides the power to the electronics and maintains the battery charge at the correct level. The Motor Control System provides the interface between the hydraulic pump motors and the power source, and provides the motor control. The SEM contains the electronics for communicating with the surface, controlling and monitoring, and data collection. The units need to have some autonomy and to be able to initiate a shutdown should the acoustics not be communicating correctly. Therefore the SEM will be microprocessor controlled. The solenoid control valves are electrically energised directional control valves, contained within the SCM for functioning the Xmas tree valves.



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29.3.4 Hydro-Acoustic Telemetry System Temperature, pressure and salinity are all major factors in control of underwater acoustic propagation. The temperature is the most important in the UK North Sea areas, as seasonal variations in the temperature/depth profile are considerable, with a corresponding impact on the sound velocity/depth profile. The degree of ray bending at any time is determined by the current temperature/depth profile and has a major impact on the acoustic link between any two fixed locations as the horizontal separation increases. With seasonal variations this link can exhibit the following characteristics: •

A direct path

•

No direct path, but one or more bounces via the surface to the seabed

•

Zero signal transfer

In addition to the variability of the main path, there are multipath signals that arrive with variable delays, amplitude and phase, causing interference with the main signal. For a permanent installation between a wellhead and a platform, the link must be capable of operating in all conditions. This is achieved by having one or more transducers deployed at different depths on the platform jacket structure. Data rates are fairly slow and 300 baud is typical, and can be lower in difficult conditions. For this reason, the control system itself has to have autonomy for emergency shutdown situations. Communication distances of 10km are practically achieved using low frequency transmission, typically in the 15-17 KHz range. Telemetry system designs of between 20 km and 30 km are claimed. SURFACE FACILITY OPERATOR INTERFACE

MODEM

SEAWATER INTERFACE

ACOUSTIC TRANSPONDER

THERMOELECTRIC GENERATOR

ACOUSTIC TRANSPONDER HYDRAULIC POWER UNIT

DATA & CONTROL MONITORING ELECTRONICS

SENSORS

ELECTRICAL POWER STORAGE

VALVE CONTROL

ACTUATORS

SUBSEA EQUIPMENT

Figure 29.2 - Autonomous Control System Schematic



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29.3.5 HAPAC The principles of the autonomous control system have been studied and proto-type tested by TOTAL in the Hunter Autonomous Power Generation and Acoustic Control Project (HAPAC). The Thermo-Electric Power Generator (THEG) was built using Bismuth Telluride p-type and Bismuth Telluride n-type as the two dissimilar semiconducting metals which can operate at up to 200ºC. Using THEGS with 6 rows in parallel and 56 plates in series, laid in a hexagonal configuration around the pipe spool, a maximum power output of 130 Watt was achieved with an internal water temperature of 120ºC and external water temperature of 4ºC. The subsea control system used had been developed by Kvaerner FSSL for the SPARCS Project, and was updated for use on HAPAC. The system was modified to be used with Simrad and Sonardyne acoustic systems. A single pressure 207 barg hydraulic supply was used for the test. The target acoustic range for the test was 10km subject to acoustic propagation conditions and platform noise levels. A high transmission level of 214db (reference to 1 micropascal pressure) was selected. An operating frequency of 15-18 kHz was selected to prevent interference with other commonly used acoustic systems. It was also a good compromise between low attenuation for operation to 10km or greater and the ability to produce directional transducer arrays that were not too large. A three element transducer array was used to provide a ±7.5º vertical beam with a broader horizontal beam of ±30º to compensate for the easier alignment of the arrays in the vertical plane relative to the horizontal plane when installed. The transmitted source level was adjustable in 6db increments from 196db to 214db, and the data rate from 10 baud to 300 baud to enable optimum performance to be achieved, and to cope with seasonal variations in the propagation conditions. An acoustic propagation study was conducted using ray path trace analysis for sound velocity/depth profile data over a range of 5.2km and in a water depth of 130m. Ray paths were computed for each month over a 12 month period to establish the seasonal variation. The results of the analysis are summarised below: •

Over the summer months, there is always a direct path from the platform to the subsea well site.

•

As the summer progresses, a thermocline develops which gets steadily deeper and thereby prevents acoustic communication at transducer depths shallower than 100m in September.

•

In winter there is no direct path but there is always a path with a single bounce from the surface.

•

The optimum depth for the platform transducer was 100m.

The Total Exploration Production HAPAC Final Technical Report was issued in April 1999.



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29.4 Alternative Technology 29.4.1 Introduction This section discusses the application of recent technology to subsea control systems, whereby a system may be improved, or made more cheaply, by benefiting from advances in compatible techniques. 29.4.2 Fibre Optics Subsea control systems have traditionally used slow but robust telemetry systems for system communications, operating over copper wire cores in umbilicals. Communications at 1200 baud using half-duplex telemetry was prevalent. This was acceptable for polling of control modules and the occasional valve command, but it is not acceptable for large amounts of data. In addition, it can take several minutes to do a total system scan and therefore the data retrieved is not available in real time. This may have been adequate in the late ‘70s when a state of the art modem was not much faster. However, the advance in telecommunications and the Internet has left these telemetry systems outmoded. There is a need for real-time telemetry in production systems, and in particular when High Integrity Pipeline Protection Systems (HIPPS) are required by the design. In addition, the requirement of additional monitoring for field diagnostics and reservoir data has exhibited the need for a step change in communication technology for certain applications. Fibre optic cables are capable of transmitting a large amount of data at a very high rate. The need for deeper water applications and the move to subsea processing has made the use of fibre-optic communication systems a serious consideration. There are two types of Fibres: Multimode and Singlemode, and the advantages and disadvantages are as follows: Multimode Advantages:

• •

Large core tolerates connector misalignment Low cost transmitters - LED technology, short wavelengths

Disadvantages:

• •

High attenuation – 3dB/km @850nm, 1.5dB/km @1300nm ‘Low’ bandwidth – 500MHz.km

Singlemode Advantages

• •

High bandwidth >2000MHz.km Low attenuation – 0.5dB/km @1310nm, 0.3dB/km @ 1550nm

Disadvantages

• •

Small core sensitive to connector misalignment More expensive transmitters – Laser technology, long wavelengths



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In both Singlemode and Multimode fibre the attenuation is caused by light travelling down the fibre is scattered out of the fibre and absorbed by the fibre.

50µm

Multimode fibre

125µm

8µm

Singlemode fibre

125µm

The high communications bandwidth on Singlemode fibre supports increased sensing and control facilities. The bandwidth is limited by the transmission system and not by the fibres themselves or the connectors. Modems are readily available developed and used in the telecomms industry and wet-mateable fibre-optic connectors have been in use since around 1997 as a controlled-environment type connector.

The connector brings together two shaped and polished fibre ends with a misalignment of less than two microns to achieve a connector loss of less than 0.5dB. The misalignment may be axial, angular or longitudinal causing loss due to light being reflected by the end of the fibre and scattered as it leaves the fibre. This reduces the amount of light entering the mating fibre. The increased bandwidth can be achieved with a reduction in size from a single electricalconductor pair, and hence a reduction in umbilical cross-sectional area, and hence umbilical cost. The move towards subsea processing will require different types of electrical equipment on the seabed. For example, for long offsets, there may be a requirement for high voltage cabling. It would not generally be cost effective or economic to install a separate power and communications cables, and hence signals running over long distances next to high voltage power conductors need to be noise tolerant. Optical fibre offers complete immunity from signal corruption caused by exposure to electromagnetic interference (EMI). Fibre optics can also provide secure and uncorrupted communications. Where a subsea field might be tied back to another Operator’s host facilities, digitally encrypted signals can be used to keep data secure. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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This can be of particular interest when using a network such as the FibreWeb™ network in the Gulf of Mexico, where fibre optic cable routes along the seabed from near Houston to near New Orleans, routing around several rigs and platforms. The fibre cable is mainly for voice communications as an alternative to radio or satellite, but the opportunity to tie-back and control a subsea development or the possibility of 100 sensors in line on any one fibre provides many opportunities for technology development. Field acreage may have been previously drilled and reserves proven that may not be economic to produce as a stand-alone development. These assets may be revisited as the technology develops and the support infrastructure develops. Fibre optic based systems offer the ability to communicate over distances of 100-200km with no subsea signal repeaters. In addition to the above, fibre optics have provided an economic and reliable solution for monitoring downhole pressure and temperature. Temperatures in excess of 1000ºC can be measured which exceeds the survivable performance of all electronic gauge systems.

Figure 19.3 - Oil Filled Jumper with Fibre Management System



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30 HIGH-INTEGRITY PRESSURE PROTECTION SYSTEMS (HIPPS) 30.1 Introduction Flowlines can be an expensive item due to their length and the wall thickness requirement for pressure containment and an applied corrosion allowance. If the flowline is designed to withstand the maximum Wellhead shut-in pressure at production start-up, the system will be over designed as reservoir pressure falls later in field life. In addition, flowing pressures will be significantly less than the shut-in pressure and hence the system will normally operate at pressures well below the design. Project feasibility should consider the economics of reducing the rated working pressure of a flowline below the maximum Wellhead shut-in pressure of the well(s) feeding it, whilst at the same time taking precautions to ensure the pressure in the flowline can never rise as high as the Wellhead Shut-in pressure. A typical field study consideration is a gas field where the reservoir shut in pressures may be high. For a flowline to be rated lower than a pressure that could potentially be applied to it requires considerable means to ensure this over pressure can never occur. If a barrier valve is placed at the Manifold just before the flowline and is shut whenever the pressure rises, only the Tree and manifold pipework need then be rated to the full shut in pressure. To achieve this, a High Integrity Pressure Protection System (HIPPS) is required. The HIPPS system is a high-availability emergency shutdown system to ensure the wells feeding the flowline are isolated whenever the pressure in the flowline exceeds an alarm point, by closing the Barrier Valves. The consequences of any decision to de-rate the flowline and introduce a HIPPS are considerable and the overall economics and safety issues including a safety case study must be carefully evaluated before proceeding along this path. An intermediate approach is to rate the flowline such that full Wellhead pressure does not cause it to rupture, but 'merely' to exceed its plastic limit. When considering the complexity of a HIPPS system and the dual/triple redundant equipment on the seabed, it may be appropriate to be able to isolate the HIPPS system later in the field life when the reservoir depletes and the well shut in pressure becomes lower. There are several different abbreviations that have been used for overpressure protection systems, such as HIPPS (High Integrity Pressure Protection System), HIPS (High Integrity Protection Shutdown system) or OPPS (Overpressure Pipeline Protection System).



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Implementation of a HIPPS 30.1.1 Requirements The requirements are therefore for a system that detects a rising pressure in a flowline and quickly shuts one or more isolation/barrier valves before the pressure can rise too high. This requires: •

A very reliable and highly available system.

•

A fast-acting system.

The main components of a HIPPS therefore comprise: •

Pressure (and other) transmitters.

•

Logic.

•

Redundant Barrier Valves.

In its simplest form, a HIPPS barrier valve, installed in the fully rated pipework section of the Process Manifold/Template, is controlled by local logic monitoring a downstream Pressure Transmitter. HIPPS control logic monitors the Transmitter and closes the HIPPS barrier valve in the event that excessive pressure is detected. Usually the implementation of a HIPPS system subsea gives rise to many other considerations during detailed design, and hazard and operability studies. This is due to the amount of dual/triple redundant equipment on the seabed, adequate system isolation, and consideration of keeping critical instrumentation hydrate free. Thus the ability to isolate the HIPPS system later in the field life should also be considered during the design phase.



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API 5000

PMV

PWV

XMAS TREE PRODUCTION STRING

FCV

HIPPS BARRIER VALVE 1

ZT

ZI

2500 ANSI

SDV

PT

SDV

ZT

PT

HIPPS VOTING

HIPPS BARRIER VALVE 2

PT

SUBSEA MANIFOLD

PT

S.P.

PT

FIC

1500 ANSI

FLOWLINE TO PRODUCTION FACILITY

TotalFinaElf DEEPWATER REFERENCE BOOK

Figure 30.1 - HIPPS Schematic

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The actual HIPPS implementation is more complex in order to assure the reliability, availability and speed, and to power and test the system. Topsides equipment will need to supply the necessary electrical and hydraulic power, which will be transmitted to the subsea equipment via an umbilical. Subsea equipment located adjacent to the Barrier Valves will provide the actual detection and actuation mechanisms. A second HIPPS barrier valve, is also monitored either side by Pressure Transmitters, which provides redundancy in case of failure or leakage of the first valve. 30.1.2 Typical system The Topsides equipment comprises: • Master Control Station (MCS) • Electrical Power Unit (EPU) • Uninterruptible Power Supply (UPS) • Hydraulic Power Unit (HPU) The Subsea equipment comprises: •

Umbilical and termination/distribution unit

•

HIPPS subsea control module and mounting base

•

Subsea Accumulator Module and mounting base

•

Hydraulic jumpers

•

Process Barrier Valves and Position Indicators

•

Maintenance, venting and test valves

Standard subsea hardware can be used for non-critical control functions, but specially designed equipment will be required for the rest of the system. These components are described below in more detail. 30.1.3 Pressure Transmitters The Transmitters used for this application are 'normal' subsea devices. Pressure Transmitters rather than Pressure switches are used, as failures can be more easily detected and pressure values are more useful. To ensure availability and prevent erroneous shutdowns, usually more than one transmitter is employed in a "2 out of 3" voting (triplicate) configuration, and different makes of sensor can be used to avoid common fault modes. Either the transmitters themselves and/or the detection logic will act in such a way that a failed transmitter is seen as a 'high' pressure and therefore trips the system. Common-mode failures due to blocked sense lines (ice, hydrates, scale, wax or mechanical damage) can be a serious problem and the design should ensure this risk is minimised.



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30.1.4 Control Hardware The control hardware monitors the Transmitters and closes the Barrier Valves when high pressure is detected. The detection and activation system is inevitably an electronic system and it should be independent of any other platform or subsea system, although data-feeds to other systems are usually available. The implementation of this is usually a dedicated subsea controller, located in a subsea control module adjacent to the Barrier Valves themselves. The HIPPS control module monitors the Transmitters and closes the valves in the event excessive pressure is detected. This operates via a certified fixed-logic electronic system and is not dependent on microprocessors or links to the surface. Thus each trip is pre-set and cannot be changed without physical access to the controller. This requires careful attention to hydraulic design to ensure pulses do not inadvertently trip the system. A secondary controller is microprocessor based and provides non-safety related and secondary functions and communicates with the surface controller. When the safety controller trips the barrier valves, the secondary controller detects this and closes all secondary and test valves (the links between the systems must be shown to be independent). The hydraulic control of the Barrier Valve requires the use of high flowrate control valves in the HIPPS control module; these are not necessarily identical to other subsea control system valves. The Barrier valves are controlled using hydraulic power, in a similar manner to a subsea control system, and so a Hydraulic Power Unit is required. This HPU can be the same unit as for the subsea control system, although the design must ensure that the reliability and availability criteria are still met; there may be auxiliary components such as a dedicated HIPPS Accumulator Unit to assure the integrity of the HIPPS supply. The control hardware will be operated using a dual-redundant electrical supply and should be fail-closed on loss of electrical power. A HIPPS system must therefore be continuously operated via a UPS. Some systems again use the same EPU as for the subsea control system but this may be undesirable as the shutdown philosophy for the subsea control system is usually such that the subsea control system does not shutdown on loss of power, whereas the HIPPS must do so. This could lead to the supplies being inadvertently shut off for maintenance, causing a HIPPS shutdown. The control hardware must be fail-safe under all modes of failure. Regulations are such that designs using computers are not permitted, as software can fail on occasions or perform in a way not originally foreseen. Required approvals typically include TÜV DIN 19250 Classes 5,6 and 7 safety standard. Standard subsea control systems are not applicable without modification, as they are usually not constructed to a fail-safe design. A Programmable Electronic Safety System or Electronic Safety System which is “Stand Alone” must meet IEC 61508 SIL requirements appropriate to the application. Electronics should NOT be integrated with other control/safety functions to avoid commonmode failures and influence on the HIPPS from other sources. The system should perform self-testing operations on a frequent basis, at least once per second, although again, the extra circuitry involved must be demonstrated not to interfere with the primary failsafe system. The whole system must be 'low-maintenance' and not require manual intervention.



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30.1.5 Barrier valves These can be 'standard' subsea isolation valves, operating in a failsafe-closed mode, although some designs may not be suitable, as the valve response time needs to be fast enough to prevent pressure excursions above the permitted limits (say, <2-5 seconds) and so the valve actuator must be carefully selected for this task. For large valves a spring-activated system may not be practical and a hydraulic accumulator provides the closure force; in this case the overall hydraulic system must again be carefully designed to ensure the system is available when required. In both cases, subsea accumulation is provided to ensure availability of the system whatever the state of the surface equipment. Pipeline pressureassist is another method to accelerate the closing time. After actuation of the barrier valves, the pressure must still be monitored downstream in case leakage causes it to continue to rise; secondary (cascade) shutdown of the Tree valves feeding the pipeline may be required, and the excess pressure may need to be bled off at the surface or via secondary flowlines or service lines. The accuracy of the position-monitoring devices may not be sufficient to detect a small degree of opening, which in time would lead to the increase in pressure. Re-opening of the barrier valves following a shutdown is via a command from the surface unit, providing the "2 out of 3" voting system permits. Venting the locked-in high pressure that originally caused the trip requires suitable additional valves and/or the use of the subsea control system with the service or test line etc, as the HIPPS itself may not have 'overrides' to permit reopening the barrier valve(s) whilst high pressure is still present. The barrier valves can also be shut by command from the surface; this will cause a pressure build-up and it is therefore advisable to shut the well in first to prevent closure against flow. This requires a link between the HIPPS and subsea control system surface controllers, or by manual procedures. Hydraulic lines from the subsea HIPPS control module are duplicated to ensure that a trapped hose could not hold a barrier valve open. Other isolation valves may be required for maintenance, testing, hydrate inhibition and pressure testing, but are not part of the primary HIPPS and are therefore controlled by the secondary controller. 30.1.6 Surface Equipment The UPS/EPU provides dual-redundant electrical power, and the HPU provides hydraulic power. These services may sometimes be shared with the normal subsea control system, with the provisos noted above. They are distributed via lines in an umbilical to the HIPPS system. It may be possible to use the same umbilical as for the subsea control system, thus economising on cost, but the HIPPS lines themselves must be entirely independent, so there will still be a certain cost impact. A dedicated HIPPS Accumulator Unit provides hydraulic reserves for peak demands. The surface HIPPS units are independent but are also connected to the MCS and other platform DCS/SCADA as required.



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30.2 System Testing A common problem is that the Barrier Valves may stick in the open (or closed) position. To minimise this risk, regular testing is performed in which the valves are completely or (usually) partially closed. To achieve this, the barrier valves are fitted with an analogue linear valve position sensor (4-20mA) which is monitored by the HIPPS module. This allows fine control of the valve position; the valve can be commanded shut until the position is seen to move then re-opened again, thus avoiding a complete shutdown. This is a common test method for SSIVs, but it should be noted that deliberately slowing the valve-closure mechanism to permit such testing contradicts the philosophy of a fast-acting system, and the design must therefore ensure that the main closure mechanism is not affected by the test-circuit design. Testing of the HIPPS itself is not easy. It would be necessary to modulate the pressure to the transmitters to check they are working - this can only be done by decreasing the pressure otherwise increasing it may set off a shutdown. The readings from each transmitter are available at the Surface controller and can be compared with readings from other pressure transmitters in the subsea control system, which gives some degree of assurance that they are operating and are in calibration; however, this does not prove the system will detect a high pressure and operate. Alternatively, the trigger points for the HIPPS could be set to a value below the current pressure; this would trip the system but by virtue of the Certification (see 30.1.4) such intervention on an operating system is not permitted, so is not feasible for routine testing. The only other method is to isolate each transmitter and increase the pressure above its trigger point via an external means, such as by methanol purging (which can also be a regular maintenance function). Doing this by remote control from the surface requires a number of ancillary control valves - a parallel arrangement would allow one leg to be tested with the other isolated, but the scope for leaving valves in the wrong position, wrong setpoints or common-mode failures etc., are significant. Clearly, therefore, the complexity of the system increases considerably if such a philosophy is required, but the only other sure way of testing is by deliberately closing a topsides valve and causing the pressure to rise, thus activating a genuine HIPPS shutdown. The subsea choke can be used to restrict the rate of increase to some extent.

30.3 Other concerns Pigging a flowline could cause the pressure to rise above the trigger point of the HIPPS, particularly if the pig sticks; thus, it is not advisable to use the wellstream as the driving force. "Fortified" zones may be required close to the topsides production facility and possibly near the subsea template to ensure that, even if the flowline does rupture, it does not endanger the platform (or flowline near the template). Similarly, flowline 'weak-link' devices may be provided to ensure any rupture occurs in a defined place. The HIPPS system can to some extent be supplemented by designing shutdown sequences into the subsea control system. A subsea control system may have algorithms to detect temperatures and pressures being within the hydrate-forming region. This system has control of Tree/manifold Valves and Chokes, and can be designed to detect rising pressure (particularly relatively slow events such as formation of wax or hydrates) and to close the Production Wing Valve and/or choke (these being the items usually closed against flow). This may be sufficient to avoid triggering the HIPPS in many cases, but the main reason why this is unacceptable as a primary HIPPS being that the subsea control system is not usually designed or approved for such high-integrity, high-availability, fast-acting purposes. Similarly, any closure of topsides valves should immediately be conveyed to the subsea control system to permit it to attempt to reduce the flowline pressure; it is not usually the case Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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that all such events are reflected back to the subsea control system (only major ones such as Platform Shutdowns) so it is feasible that the inadvertent closure of a topsides block valve could trigger the HIPPS, unless all such events are immediately followed by closure of Tree/Manifold valves and chokes. This requires a better integration of the topsides and subsea facilities and in practice can be difficult to implement, particularly where a topsides system already exists when a new subsea field is connected to an existing Platform. It is very easy to manually close a topsides riser or separator valve, without prior subsea action, and the system effects of this, including the 'water-hammer' effect, may well cause the pipeline pressure to be exceeded. Pressure-testing of a pipeline would also activate the HIPPS, which should therefore be taken into account when planning such operations - again, only an override would permit such testing past the Barrier Valve(s) themselves.

30.4 Summary A HIPPS flowline protection system is readily achievable using existing proven technology, but there are consequences to the overall subsea and topsides control system designs in implementing such a system. The need for overall Project commitment to a HIPPS system is mandatory, as there are farreaching consequences in taking this route to all aspects of developing a new field, particularly when being tied-back to an existing Platform. The total cost of ownership must be fully accounted for in determining the feasibility of having a low-pressure rated pipeline, and a number of areas have been highlighted which will, in practice, add to the development cost and reduce the advantage of lowering the pipeline design pressure. The effects of adding a HIPPS system depend also on the nature of the Field Development Project itself, and unless being implemented at the start of a completely new Development, will have cost implications on existing systems which may be unacceptable or difficult to implement. Further precautions can be implemented using technology within existing designs of Subsea Control System. A dedicated HIPPS module can then be added to the control system, sharing the power / hydraulics / communications (albeit with certain provisos), to provide overall protection via a dedicated HIPPS Barrier Valve, should the well control system fail to maintain pressure in the safe region. Nevertheless, it is evident that a simple commercial decision to economise on pipeline costs results in a considerable and complex outlay for a system to adequately and reliably prevent the pipeline being over pressured.



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31 APPENDIX A - AUTHORS & VENDOR CONTACT DETAILS Subsea Control Deepwater Reference Book Authored by: Tel: +44 (0)20 7481 8838

Subsea Control Services Limited 4 Gun Wharf

Fax: +44 (0)20 7480 7314

Wapping High Street

www.subseasystems.co.uk

London E1W 2NH UK Engineers and Consultants – Independent Since Formation in 1984

Subsea Control System Manufacturers (Listed in Alphabetical Order) ABB Offshore Systems Ltd

ABB Offshore Systems Inc

2 High Street

8909 Jackrabbit Road

Nailsea

Houston

Bristol BS19 1BS, UK

Texas 77095, USA

Tel: +44 (0)275 810800

Tel: +1 (0)281 855 0973

Fax: +44 (0)275 851467

Fax: +1 (0)281 855 0973

_____________________________________________________________________________________________

Brisco Engineering Ltd Palmer House Gapton Hall Industrial Estate Great Yarmouth Norfolk NR31 0NN, UK Tel: +44(0)1493 668811 Fax: +44(0)1493 651137 _____________________________________________________________________________________________

CAC Ltd

CAC Inc

Viking Road

22001 North Park Drive

Gapton Hall Industrial Estate

Kingwood

Great Yarmouth

Houston

Norfolk NR31 0NU, UK

Texas 77339-3804, USA

Tel: +44 (0)1493 652611

Tel: +1 (0)281 348 1033

Fax: +44 (0)1493 444598

Fax: +1 (0)281 348 1280

_____________________________________________________________________________________________

Cameron Controls

Cameron Controls

Cooper Cameron (UK) Ltd

Cooper Cameron Inc

Cooper Cameron House

10810 North West Freeway

5 Mondial Way

PO Box 1212

Harlington, Hayes

Houston

Middlesex UB3 5AR, UK

Texas 77251-1212, USA

Tel: +44 (0)20 8990 1800

Tel: +1 (0)713 683 4600

Fax:+44 (0)20 8990 1888

Fax: +1 (0)713 683 4363



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Kongsberg Offshore a.s.

FMC Kongsberg Inc

P.O. Box 1012

1777 Gears Road, Box 3091

N-3601 Kongsberg

Houston

Norway

Texas 77253, USA

Tel: +47 (0)32 73 98 98

Tel: +1 (0)281 448 0211

Fax: +47 (0)32 73 93 78

Fax: +1 (0)281 591 4030

_____________________________________________________________________________________________

Kvaerner Oilfield Products Ltd

Kvaerner Oilfield Products Inc

Kvaerner House

1255 North Post Oak Road

68 Hammersmith Road

Houston

London W14 8YW, UK

Texas 77055, USA

Tel: +44 (0)20 7559 6000

Tel: +1 (0)713 685 5700

Fax: +44 (0)20 7559 6100

Fax: +1 (0)713 685 5707



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32 APPENDIX B - TYPICAL CONTROL SYSTEM DRAWINGS



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Figure 32.1 Total Nuggets Subsea Control System Block Diagram



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Figure 32.2 - Total Nuggets Composite Umbilical Block Diagram Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK DEEPWATER INSTALLATION VESSELS

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TABLE OF CONTENTS

1

INTRODUCTION ............................................................................................................ 4 1.1 SCOPE ...................................................................................................................... 4 1.2 REGULATIONS, CODES, STANDARDS & SPECIFICATIONS .............................................. 4 1.3 DEFINITIONS & ABBREVIATIONS .................................................................................. 5 1.4 REFERENCES ............................................................................................................. 6 1.5 ACKNOWLEDGEMENTS ................................................................................................ 6

2

DEEPWATER INSTALLATION TASKS......................................................................... 7 2.1 INTRODUCTION ........................................................................................................... 7 2.2 INSTALLATION TASKS .................................................................................................. 7 2.3 LIFTING REQUIREMENT ............................................................................................... 7 2.4 LAYING REQUIREMENT................................................................................................ 8

3

INTERFACE REQUIREMENT........................................................................................ 9 3.1 INTRODUCTION ........................................................................................................... 9 3.2 STORAGE AND LAYING OF PRODUCTS .......................................................................... 9 3.2.1 General .........................................................................................................................9 3.2.2 Product Safe Handling..................................................................................................9 3.2.3 Installation and Laying Parameters ............................................................................10 3.2.4 Clamping Pressure .....................................................................................................10 3.2.5 Load Matrix .................................................................................................................11 3.2.6 Laying Accuracy, Monitoring & Control ......................................................................12 3.3 LIFTING & INSTALLATION OF STRUCTURES ................................................................. 13 3.3.1 General .......................................................................................................................13 3.3.2 Subsea Structures Safe Handling ..............................................................................13 3.3.3 Installation Accuracy, Monitoring & Control................................................................14 3.4 REMOTELY OPERATED VEHICLES .............................................................................. 14

4

LAY ANALYSIS ........................................................................................................... 16 4.1 GENERAL ................................................................................................................. 16 4.2 PIPELINE BUCKLING DESIGN ..................................................................................... 16 4.3 DEEPWATER PIPELAY METHOD ................................................................................. 17 4.3.1 General .......................................................................................................................17 4.3.2 S-Lay...........................................................................................................................17 4.3.3 Steep S-Lay ................................................................................................................17 4.3.4 J-Lay ...........................................................................................................................18 4.3.5 Reel-Lay......................................................................................................................18 4.4 S-LAY VERSUS J-LAY ............................................................................................... 19 4.5 STEEP S-LAY STRAIN ............................................................................................... 21 4.6 REEL-LAY STRAIN .................................................................................................... 22 4.7 DEEPWATER J-LAY PARAMETERS (RIGID PIPE, FLEXIBLE & UMBILICAL) ....................... 24 4.7.1 Rigid Pipe....................................................................................................................24 4.7.2 Flexible Lines ..............................................................................................................27 4.7.3 Umbilical Lines............................................................................................................28 4.8 INSTALLATION METHOD LIMITATIONS ......................................................................... 29

5

DYNAMIC POSITIONING EQUIPMENT & CLASS ...................................................... 30 5.1 GENERAL ................................................................................................................. 30 5.2 DP FUNCTIONAL REQUIREMENT ................................................................................ 30 5.2.1 Introduction .................................................................................................................30 5.2.2 Power System.............................................................................................................31 5.2.3 Thruster System..........................................................................................................31 5.2.4 DP References and Control System...........................................................................31 5.3 DP CAPABILITY DEFINITION (& PLOTS) ...................................................................... 33


DEEPWATER INSTALLATION VESSELS

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5.4 SAFETY REQUIREMENT ............................................................................................. 34 5.4.1 Introduction .................................................................................................................34 5.4.2 DP System FMECA ....................................................................................................34 5.4.3 Hazardous Operation Analysis ...................................................................................34 6

INSTALLATION AND LAYING EQUIPMENT DESCRIPTION ..................................... 35 6.1 GENERAL ................................................................................................................. 35 6.2 STORAGE EQUIPMENT .............................................................................................. 36 6.2.1 Basket Storage Carousel............................................................................................36 6.2.2 Horizontal Powered Reel ............................................................................................37 6.2.3 Vertical Powered Reel ................................................................................................39 6.2.4 Dolly Base ...................................................................................................................41 6.3 LAYING EQUIPMENT .................................................................................................. 42 6.3.1 Tensioner ....................................................................................................................42 6.3.2 Overboarding Chute....................................................................................................43 6.3.3 High Departure Angle Stinger (rigid pipe laying)........................................................44 6.3.4 Flexible and Rigid Pipe J-lay Ramp............................................................................45 6.3.5 Flexible and Reeled Pipe J-Lay Ramp .......................................................................47 6.3.6 Rigid Pipe J-Lay Ramp ...............................................................................................48 6.3.7 J-lay Ramp using Hang-Off Collar..............................................................................49 6.3.8 Flexible Vertical Laying System..................................................................................51 6.4 ABANDONMENT AND RECOVERY W INCH..................................................................... 53 6.4.1 General .......................................................................................................................53 6.4.2 Linear Traction Winch.................................................................................................53 6.4.3 Capstan Friction Winch...............................................................................................54 6.4.4 Flexible Pipe Follower.................................................................................................54 6.5 WELDING AND TIE-IN TECHNIQUES ............................................................................ 55 6.5.1 General .......................................................................................................................55 6.5.2 Conventional Welding Technique...............................................................................56 6.5.3 Electron Beam Welding ..............................................................................................60 6.5.4 Flash Butt Welding......................................................................................................61 6.5.5 Radial Friction Welding...............................................................................................64 6.5.6 Mechanical Connectors ..............................................................................................65 6.6 WELD INSPECTION ................................................................................................... 66 6.6.1 Introduction .................................................................................................................66 6.6.2 Radiographic Testing..................................................................................................66 6.6.3 Ultrasonic Testing .......................................................................................................68 6.6.4 Remarks......................................................................................................................69

7

DEEPWATER INSTALLATION VESSELS .................................................................. 70 7.1 HEAVY LIFT VESSELS ............................................................................................... 70 7.2 PIPE LAY VESSELS ................................................................................................... 72 7.2.1 J-Ramp Lay Vessels ...................................................................................................72 7.2.2 Vertical Reel Lay Vessels ...........................................................................................74 7.2.3 Horizontal Reel Lay Barges ........................................................................................76 7.2.4 Steep S Pipe Lay Vessels ..........................................................................................78 7.3 FLEXIBLE LAY VESSELS ............................................................................................ 80 7.4 UMBILICAL LAY VESSELS .......................................................................................... 82



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1


INTRODUCTION

1.1

Scope

As offshore oilfields are discovered in increasingly deeper waters, the capabilities of existing installation and pipelay vessels are being exceeded. The offshore industry is faced with the need to improve the operating capabilities of existing vessels or undertake the construction of new vessels specially designed for operation in very deep water. The scope of this study is to review the existing and the new built or converted deepwater installation vessels and to cover the key issues such as :

1.2

•

the typical deepwater installation tasks and related constraints, as further described in chapter 2

•

the recent offshore accidents in the Gulf of Mexico just highlight the importance of interface engineering that is needed to properly load and install a product (flowlines or umbilical) or structure with the adequate means (cranes, winches, tensioner, lay ramp, etc.) as further analysed in chapter 3

•

the different lay techniques (Steep S-lay, J-lay, Reel-lay) are further analysed in chapter 4 with its constraints, limitations, advantages and disadvantages

•

because of the water depth and the scattering of FPS mooring lines, wells, flowlines, umbilical and other subsea structures, deepwater installation vessels must be equipped and operated in 'dynamically positioned', exclusively by means of propeller and thruster forces. The dynamic positioning system and DP class type are further detailed in chapter 5

•

the installation means and the laying equipment are further described in chapter 6

•

and the subsequent chapter 7 will provide a general description of the existing and new or converted deepwater installation vessels (i.e. heavy lift vessels, deepwater pipelay vessels, and deepwater flexible pipes and umbilical lay vessels)

•

finally the annexes will provide the detailed technical description of the available deepwater installation vessels, along with the addresses of the deepwater installation contractors.

Regulations, Codes, Standards & Specifications •

International Maritime Organization, MSC Circular 645, 113 IMO, Guidelines for Vessels with Dynamic Positioning Systems

•

The International Marine Contractors Association IMCA M 140, Specification for DP Capability Plots

•

DNV 1997, Rules for Classification of Steel Ships

•

DNV 1994, Rules for Certification of Lifting Appliances

•

DNV 1996, Rules for Submarine Pipeline Systems



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1.3



Capability plots

DP vessel

A theoretical polar plot of the vessel capability for specific conditions of wind, waves, current from different directions and with different thruster combinations. Dynamically positioned vessel means a unit, a ship or vessel which automatically maintains its position and heading with respect to one or more reference, exclusively by means of thruster force.

FPS

It comprises all equipment, sub-systems, control systems and back-up systems that directly or indirectly effects the position keeping ability of the vessel; such as power system control, measuring system, thruster system, reference and measuring system, control system, etc. Differential GPS plus a correction supplied by one or more receivers at fixed location, accurate for Dynamic Positioning The conduit system e.g. steel pipeline, flexible line, bundle, etc., divided in two parts: static "sealine” section resting on seabed and dynamic "riser" section from seabed to surface Floating Production Systems: TLP, SPAR, FPSO, Semi-submersible, etc.

FPSO

Floating Production Storage and Offloading vessel

HAZOP Sealine

Hazardous Operation Analysis "Static" section resting on seabed of a conduct for the flow of liquid and/or gas

Pipeline

The conduit system used to export oil and gas from fixed or floating production system "Dynamic" part of flowline connecting sealine to the termination point of platform Failure Modes Effect & Criticality Analysis

DP system

DGPS Flowlines

Riser FMECA

Global Positioning System using satellites to position a ship

GPS LARS

Launch & Recovery System (e.g. ROV handling system)

PLEM

Pipe Line End Manifold

PLIM

Pipe Line Intermediate Manifold

Redundancy

Ability of a system or component to maintain or restore its function, when a failure has occurred. Ability of a system or a software program to perform its required function without failure to cause an interruption in DP control in a period of 2000 hrs of DP operation. Remote Operated Vehicles encompassing : Observation, Survey and Working ROVs. Subsea Production System, encompassing all structures & systems, subsystems, equipment, components outwit the Umbilical & Flowline System.

Reliability

ROV SPS

Safe working limits The environmental limits that a vessel follows for DP safe working position, taking into account certain equipment failures.

TLP

Tensioned Leg Platform

Umbilical

With the same split between 'static' and 'dynamic' applications as for the Flowlines.

UTA or UTU

Umbilical Termination Assembly or Umbilical Termination Unit.



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1.4

1.5


References 1.


2.

In-house technical offshore vessel database

3.

In-house experience in deepwater operations and installation vessel management

4. 5.

Marine Contractor Vessel leaflets Deepwater Field Development – Reference Book – “Tie-in Methods”

6.

Deepwater Field Development – Reference Book – “Sealines”

7.

Deepwater Field Development – Reference Book – “Riser Systems”

8. 9.

Deepwater Field Development – Reference Book – “Umbilicals” Deepwater Field Development – Reference Book – “Deepwater ROV & TOOLS”

Acknowledgements




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2


DEEPWATER INSTALLATION TASKS

2.1

Introduction

Floating Production Systems (FPS) is widely considered as the most practical and commercially attractive solution for the development of deepwater (1000 m) and ultra deepwater (2000 - 3000 m) oil and gas reserves. Depending on the hydrocarbon reservoir characteristics, the X-mas trees can be either in surface (“dry” configuration) or subsea installed. In general FPS such as TLP, SPAR and Deep Draft Semi-submersible Structures (DDSS) will serve the 'dry' configuration alternative, with the remaining systems such as FPSO and Semisubmersible Structures to remotely control the subsea trees from the floater.

2.2

Installation Tasks

A proven deepwater arrangement is the use of sealines and risers connecting subsea wells to moored FPS (FPSO, Semi-submersible and DDSS). Such deepwater development scenarios will typically require the following installation tasks :

2.3

•

lifting and installation of mooring lines (a combination of chains, steel wires or synthetic ropes, and anchors or piles)

•

lifting and installation of tethers (for TLP or SPAR "Seastar")

•

mooring of FPS and offloading buoy

•

topside crane heavy lift of process modules onto the FPS (SPAR, TLP, FPSO, etc)

•

lifting and installation of subsea templates, manifolds and production systems

•

laying of sealines and risers

•

laying of control umbilical

•

subsea tie-ins

Lifting Requirement

Topside process modules are generally designed to be within the existing heavy lift crane vessel capabilities which can range from 3000 tons (Derrick Barges: DB50) up to 13000 tons capacity (Semi Submersible Crane Vessels: Saipem 7000, Heerema Thialf) . For the installation of subsea structures and because of the water depth, the general practice is to lift the subsea structures (of some 300 tons) on surface with the vessel crane and to cross-haul it (under water) to a deck winch cable, which will then lower the subsea structures to the seafloor. The existing heavy lift vessels (see annex 1) are well adapted and in sufficient number to address the above needs.



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2.4


Laying Requirement

The development of new deepwater oilfields uses generally small to medium diameter pipelines (e.g. the 12" Marlim (Gulf of Mexico) pipeline laid by Allseas Lorelay in 1650m of water). Export pipelines (mainly gas trunkline) with larger diameters of 20" to 30" and heavy wall to prevent hydrostatic collapse, will impose laying tension (above 500 tons) which existing lay vessels cannot cope with. The new or converted pipelay vessels should have an operating range and ability to lay small (12-inch) to medium diameter (22-inch) pipelines and perform connection in 2000m water depth and beyond (i.e. 2500m – 3000m). There is an immediate need for pipelay vessels capable of installing these pipelines efficiently in deep waters. The ability to install these flowlines at a low cost is critical because, in many cases, the full cost of constructing these lines can determine the economic viability of offshore fields in deep waters.



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3



3.1

Introduction

The main interface requirements in the deepwater installation of subsea components and/or structures are related to: •

Storage and safe installation of products (umbilical and flowlines)

•

Lifting and installation of subsea structures

•

Remote Operated Vehicles

They are further described in the following sections.

3.2 3.2.1

Storage and Laying of Products General

The storage and subsea installation of products are to be performed in a timely and safe manner, taking into account all site limitations, typically: • weather conditions • seabed soil conditions and visibility • other site constraints (mooring lines, other subsea structures, etc.). For this purpose the storage and laying equipment must be designed, built and operated to suit the conditions in which they are to perform, taking account of the products properties, installation constraints and emergency situation as defined by the HAZOP/HAZID sessions. For all offshore activities or tasks, laying and installation detailed procedures must be provided and weather limitations identified (waves, winds, currents, etc) in relation to vessel heading. Reversal of all operations (e.g. laying) must be possible and related procedures should also be provided.

3.2.2

Product Safe Handling

The products to be laid or installed are typically : • steel sealines and risers • flexible flowlines and risers • control umbilical (electrical, hydraulic, steel tubes, service lines, etc) in 'static' or dynamic riser applications • power electric cables • other types of flowline such as bundle, etc The products must be handled, stored, seafastened, transported and installed in a safe manner and according to the specified requirements (e.g. product properties/load capacities) and procedures. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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For each product, the installation or laying parameters (dynamic mode) and product load capacities must be calculated and analyzed against the vessel and equipment performance and capabilities. A formal FMECA study for the laying and installation equipment (e.g. including all ancillaries such as abandonment & recovery means) is to be performed. The objectives being to demonstrate that the product will not be damaged by the installation or laying equipment during normal operation and back-up procedure exists, in case of emergency situation arising from environmental condition changes or vessel equipment failures. The product bending radius and tension must be accurately controlled (i.e. compression avoidance through monitoring of tension and product departure angle on lay vessel) during handling and laying operation; in particular during critical operations such as line initiation, over boarding of intermediate pipe fittings, lay-down of end termination, cross-hauled and pull-in operations.

3.2.3

Installation and Laying Parameters

The following installation and laying parameters must be analysed: • nominal and maximum dynamic lay tensions for empty product in submerged conditions • maximum hold-back tension in case of product 'wet buckle' (flooded condition) • minimum bending radius vs. applied dynamic tension (combined with bending) • touch down point distance from lay vessel • sag bend radius • maximum stress level • accumulated strain and maximum residual as-laid strain The above installation and laying parameters must form the basis for the laying & installation procedures. As a result of the HAZOP/HAZID sessions, an emergency & contingency procedures must be provided for all identified hazardous activities.

3.2.4

Clamping Pressure

With respect to lay tensioner clamping pressure, product acceptance criteria uses as basis for selection of clamping pressure must be provided. Such clamping pressure shall consider the effects on pressure containing elements, load bearing elements and electrical cables. Tensioner track number, length and contact pad type & shape will be selected based on product size, capacity and constraints as well as established equipment operation procedures. The tensioner must be fitted with a safety device that ensures that the caterpillar track cannot open while the product is under tension.



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3.2.5


Load Matrix

The possible damage scenarios to be evaluated for the installation phase are : Crushing Product crushing resistance is to be checked against laying equipment characteristics during product handling, such as reeling, packing, passes through straightener, tensioner, roller, gutter, hang-off or hold-back clamps, etc. Excessive Pull Actual tension combined with other loads (e.g. bending, torsion) is to be compared against product axial resistance load. Excessive Bending Special care shall be taken to avoid excessive bending during product overboarding with intermediate connections, PLIM, PLEM, subsea splice, buoyancy modules, clamps, etc. Tearing Sharp edges and abrasive surfaces shall be avoided and the clamping force properly selected. If the product passes a gutter/chute, it shall be verified that the friction (products vs. gutter) will not damage the outer sheath. Excessive Twist The product allowable twist (angle°/m) must be specified and excessive twist avoided during the installation phase (e.g. during riser cross-haul to floater or fixed structures). Collapse/Compression The laying parameters and procedures must carefully avoid exposure of the products to local loads superior to the maximum design loads. To ensure that the installation will be carried out in such a way that the different product design capacities are not exceeded, all relevant loads (dynamic mode) and their combinations are to be considered. A load matrix (load cases and loads) are to be established based on the selected installation method, vessel & equipment and specified environmental conditions. The load matrix must be used to verify if all relevant load combinations have been considered and the product design capacities are not exceeded when being handled by the installation or laying equipment.



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A typical load matrix is provided as follows in table 1: Case

Position

Laying

Load Combination

Damage Scenarios

Comments

Tensioner

Max. tension vs. clamping pressure at weather limits

Crushing, Tearing

For laying this includes normal, far and close position of vessel to touch-down-point

Ramp, Gutter, Chute, Rollers

Max. tension and bending contact at roller ramp and weather limits

Crushing, Tearing, Excessive Bending and Tension

As above

Straightener, Aligner

Max. tension and bending contact lateral point loads

Crushing, Excessive Bending and Tension, Tearing

Sag bend & touch-down

Min. tension at weather limit inducing compression at bending

Excessive Bending, Further Product abandonment & recovery is to Twist, Compression be considered

Accumulated strain level Fatigue life limitation on riser application

Pull-in

Bellmouth, J-tube Max. tension and bending at contact radius and weather limits

Excessive Bending, For cross-haul of Riser, twist angle is to be Crushing, considered Ovalisation and Tearing

Docking

Riser structure & base

Min. radius & Max. tension inducing bending, compression at weather limits (induce heave)

Excessive Bending, For laying this include normal, far and close Tearing, position of vessel to touch-down-point Compression

Max. pressure & tension, Min. bending

Crushing, Tearing, Leakage, Burst, Yield in pipe/tube

Hydrotest All applicable positions

Any weather limitation during riser pressure test is to be considered

Table 1 - Load Matrix

3.2.6

Laying Accuracy, Monitoring & Control

As a minimum, the following parameters must be monitored, recorded and displayed in a suitable location (e.g. lay control room, DP bridge) during all laying operations : • Line tension and departure angle • Touch-down point monitoring, e.g. using ROV • Line length paid out from vessel • Vessel position & heading and layback distance • Laying speed • Water depth The tension applied to the line must be continuously controlled and recorded in order to avoid sudden changes in line tension, and to ensure line routing within the specified laying tolerances. A protocol & control system between the vessel DP and the laying equipment will allow the continuous and safe product laying within a pre-determined track with or without turning points.

At completion of installation or laying operations the line end shall be lowered onto the seabed under controlled conditions and abandoned in its target area within a specified heading. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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3.3


Lifting & Installation of Structures

3.3.1

General

Lifting and installation of topside process modules, or subsea structures must be performed in a timely and safe manner, taking into account all site limitations (see section 3.2.1). For this purpose the dedicated lifting and installation equipment (cranes, winches) must be designed, built and operated to suit the conditions in which they are to perform. More specifically taking account of the structures installation criteria and constraints, as specified by the designer/manufacturers and national codes/certifying authority rules (e.g. Det Norske Veritas [DnV], American Petroleum Institute [API], Lloyds Register of Shipping [LRS]). For all offshore activities or tasks, lifting and installation detailed procedures must be provided and weather limitations identified (waves, winds, currents, etc) in relation to vessel heading. 3.3.2

Subsea Structures Safe Handling

The subsea components and structures to be lifted and installed are typically : •

mooring lines and anchors

•

foundation bases (e.g. suction, gravity, pile)

•

manifold structure guide & support bases

•

manifolds / templates

•

X-mas trees

•

manifold ancillary components (e.g. pigging loop, module control pods,)

•

closing spool pieces

•

protective structures

The subsea structures must be handled, stored, sea-fastened, transported, offshore lifted and installed in a safe manner all in accordance with the specified requirements (e.g. SPS's manufacturer) and procedures. For each structure, the lifting and installation parameters (dynamic mode) must be calculated and analysed against the vessel and equipment performance and capabilities. Reversal of the installation operations must be possible. The deck handling system and the lifting devices must be designed to control and prevent the pendulum movements of the subsea structures between leaving the deck storage area, passing through the splash zone and safely landing on the seabed. The landing criteria (speed, energy) must be defined through the SPS manufacturer interface activities. The following landing criteria are to be considered as typical for deepwater installation (preliminary data for further evaluation): •

maximum heave amplitude : 1 m

•

maximum landing speed : 0,2 m/s (manifold), 0,5 m/s (manifold base structure)

•

landing criterion : 1 kJ

A formal FMECA study for the handling, lifting and installation of equipment is to be performed. The objectives being to demonstrate that the subsea structures will not be damaged during normal operation and back-up procedure exists, in case of emergency situation arising from environmental condition changes or vessel equipment failures. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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3.3.3


Installation Accuracy, Monitoring & Control

The subsea structure installation accuracy must be performed in accordance with the SPS manufacturer requirement. The following installation tolerances are to be considered as typical (preliminary data for further evaluation): • • •

Lateral position within +/- 5 m from it's nominal position Heading of structure within +/- 2.5° Maximum inclination relative to horizon within +/- 1.5°

As a minimum, the following installation parameters must be monitored, recorded and displayed in a suitable location (e.g. installation control room, DP bridge) during the lifting and installation operations: • • • • • •

Load tension monitoring Lift line paid out from vessel Vessel position & heading Subsea structure depth monitoring Water depth Touch-down monitoring e.g. using ROV

The tension applied to the line must be continuously controlled in order to avoid sudden changes in line tension (snatch loads). 3.4

Remotely Operated Vehicles

Remotely Operated Vehicles (ROVs) are required for all subsea operations and assistance activities, such as: • • • • • • • • • • • • • • •

route survey, debris removal observation & touch down point monitoring during product lay observation, monitoring and landing of product intermediate manifold and PLEM, in pre-determined target area subsea structures observation, guiding, monitoring, landing & locking spool piece tree jumper metrology and tie-ins flying lead tie-ins between PLEMs, manifolds and trees operations of valves as primary or override functions video monitoring, during tool maneuvering and positioning hot stab for hydraulic primary and secondary tool operations torque operation on subsea valves/panels/clamp connectors water jetting and dredging connection of lifting gear post survey (as built) primary support for tie ins tools etc

The ROV system must be depth rated to project max water depth. For most ROV-dependent tasks, there is no substituted solution. If the ROV fails or is unavailable when required for such an activity, the vessel-based subsea operations will be suspended. So ROV reliability and equipment back-up philosophy are critical considerations to ensure a 24 hrs availability during subsea interventions. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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For deepwater operations, special attention shall be paid to the ROV umbilical and tether management system in terms of design and operating procedures. Due to the ROV water depth descent & ascent times and system redundancy requirement, the following table 2 sets the basic and typical number & type of ROV spreads:

Subsea Tasks

Working ROVs

Survey ROVs

Observation ROVs

Lay Monitoring, A&R activities

1

1

Subsea Structure Installation

2

Pull-in, Cross-haul

1

1

Tie-Ins

2

1

Hydrotest

2

Table 2 – ROV requirements

The proposed ROV number & type for each dedicated vessel shall be analysed and documented on this basis. The ROV vehicle will be launched using the over-the-side method or through the moonpool and will require a dedicated Launch & Recovery System to control the pendulum movements on deck and through the splash-zone. Such handling system shall be designed, built and operated to suit the conditions in which they are to perform. On a DP vessel the position for the safe launching and recovery of ROV vehicles shall be evaluated, based on vessel motions and thruster positions. As a minimum, the ROV deck equipment will include : •

electro-hydraulic umbilical winch complete with drum, cables and umbilical capable of operating in required water depths

•

ROV control cabin fully equipped (i.e. monitor recorder with hard copy print out off the screen), with air conditioned

•

direct communication and telephone links between the ROV control cabin and the laying & installation room and DP control room facilities

•

workshop cabin

•

all required spare parts for above ROV vehicle, LARS and other deck equipment

Please refer to the document “Deepwater ROV and TOOLS” (Reference 9) of Deepwater Field Development – Reference Book, for further details on ROV technology, capabilities and requirements.



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4


LAY ANALYSIS

4.1

General

The physical scale of deepwater pipeline installation possesses the biggest challenge to offshore contractors in being able to provide bigger and stronger equipment (& vessel) to handle installation at such depths (2000-3000 m) in an economic manner. Important parameters in pipeline design are (1) steel material, (2) diameter and (3) wall thickness. The pipeline material will be dictated by the produced fluid or gas corrosion properties and the diameter is chosen to suit particular maximum flow of the wells it is serving. The wall thickness often needs to be chosen with particular care, as the weight of pipe suspended directly from the lay vessel will influence the amount of tension required to hold the pipe during the laying operation. At such depth a few millimetres of additional pipe wall thickness can make the operation beyond existing vessel lay capabilities. Thicker wall pipe will also have a costly impact on material cost, transportation and installation, as longer offshore welding time will be required. Several pipelay methods from a vessel (barges, ships, semi-submersibles) can be considered : S-Lay, J-Lay and Reel-Lay. The following sections will further analyse the above pipe design considerations and the laying configuration constraints.

4.2

Pipeline Buckling Design

Designing the pipe to resist deepwater hydrostatic pressure is the major factor which will affect the pipe wall thickness. Consideration must be given to both, (1) local buckling and (2) propagation buckling. Local buckling can occur during offshore pipe lay operations when the pipe is under a combination of loads due to external hydrostatic pressure and bending moments, which can initiate a local buckle. Alternatively such buckling damages or dents that can occur if the lay tension is lost during the pipe lay phase or by trawl board damage, etc. In these cases, if the external pressure is high enough, the dent or local buckle may propagate along the pipeline in a phenomenon known as 'Propagation Buckling'. This propagation buckling is driven solely by the water pressure, in which a local buckle in an offshore pipeline changes its geometry from a transverse dent to a longitudinal buckle and propagates along the pipeline, collapsing it along its length. Once initiated it will not stop until it either encounters an obstruction on the line or reaches shallower water where the external pressure will be less than the propagating pressure. Since the propagation buckling pressure is much less than the local buckling pressure, the pipe design based on the propagation criteria will result in thicker wall pipe and the resulting tension can be very well beyond existing lay vessel capabilities and become an economic issue. The alternative is to remain with the optimum wall thickness to resist local buckling collapse design criteria (to suit existing lay vessel capabilities) and to install buckle arrestors at suitable intervals. Should a propagation buckle unfortunately occur (i.e. loss of lay tension), then only a short section of line would require to be replaced.



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4.3 4.3.1


Deepwater Pipelay Method General

Increasing water depths will exacerbate the problem areas such as : • top tension necessary to hold and control the pipe catenary • pipeline initiation method • abandonment and recovery of the pipelines • touchdown point monitoring and survey • economic need for lay speed

4.3.2

S-Lay

Traditionally pipelay is carried out from a purpose built barge or vessel and in an S-lay configuration. The lay barge allows the pipe to be welded, controlled and coated in a continuous production system based on different workstations (i.e. 5-7 stations) to form a 'firing line'. This leads to a fast production process even when dealing with large diameter pipes (e.g. 36”), typical lay rates from 2 km/day and up to 6 km/day (on occasion) can be achieved. However, because the pipe is assembled in the horizontal position it needs to be laid off the back of the vessel in an S-shaped catenary and supported by a stinger to prevent the pipe from buckling. Because of the pipe departure angle at the stinger tip (30-40 degree range from horizontal, depending on water depth and pipe diameter), S-lay intrinsically requires much higher tensions (than J-lay) to control the pipe curvatures (see next section 4.4). Furthermore the long lay back distance of pipe touch down point in deepwater with S-lay is also problematic and restricts its ability to lay around a curve. The deepest S-lay has been performed by SAIPEM Castoro Sei (20" diameter) at a depth of 615 m in the Strait of Sicily.

4.3.3

Steep S-Lay

To reduce these high tensions the stinger departure angle can be increased to 60°- 80° range (near vertical angle) in a configuration known as 'Steep S-lay' . This however means a longer and deeper stinger (e.g. 60m - 100 m) leading to more awkward handling problems and greater weather sensitivity (see section 6.3.3). Furthermore the high pipe weight tension combined with the steep radius of curvature will introduce an elasto-plastic bending and a residual pipe strain in the 0.4% - 1% range (see section 4.5). The current deepest 'Steep S-lay' has been performed by Allseas Lorelay (12" diameter) at a depth of 1650 m on Amoco Marlim (Gulf of Mexico).



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4.3.4


J-Lay

This is the second configuration for laying of pipe, where the pipe departs from the lay vessel at a near vertical angle (e.g. 85°-87°). There is no over-bend to maintain as in the above case. The pipe hangs in catenary and curves towards the horizontal as it approaches the seabed (i.e. sag bend radius). A smaller tension is necessary to maintain a satisfactory curvature at the sag bend. To control the stresses and prevent buckling, the major part of the tension requirement is simply to hold the submerged weight of the pipe. Residual axial tension on pipe laid by J-lay is significantly less than with the S-lay method (see next sections 4.4 and 4.7). Since the pipe is departing from the vessel in the near vertical position, this implies that the welding should be done in the near vertical as well. Since it is not practical to have a vertical 'firing line' as in the S-lay, the pipe is assembled (welded) by stalk of 2, 4 or 6 joints. A 6 joint stalk is considered to be the current practical limit for up-righting (i.e. Heerema Balder J-lay equipment). The pre-fabricated stalk of joints is up-righted from the horizontal position to the vertical lay ramp, where it is welded at a single station. This makes the production process much slower than for S-lay. Typically, 1 km/day to 2 km/day can be achieved depending on the pipe diameter and wall thickness. The pipe needs to be held (in the vertical position) while welding of the stalk joint is taking placed; three alternatives can be adopted : (1) tensioners, (2) pipe collar or (3) hang-off friction clamp. The current deepest J-lay has been performed by J.Ray Mc Dermott DB50 (18"diameter) at a depth of 950 m on Shell Mars (Gulf of Mexico). Because the pipe lay (in 'J' configuration) is without residual strain, it is the preferred method for laying steel catenary riser : • Shell Auger TLP, 2x12" oil & gas export risers in 870 m • Petrobras Marlim 10" gas-export from P26 to P18 semi-submersibles in 910 m water depth.

4.3.5

Reel-Lay

The third method for laying deepwater pipelines is by the reel lay ship. This installation technique can be considered as similar to the J-lay approach, with however a main difference as the pipe is continually fed down an adjustable lay ramp from a large storage reel mounted on the ship (see section 4.6). Prefabricated pipe lengths (e.g. 500 m to 1000 m) are welded together and spooled onto the ship reel at an onshore fabrication yard (spoolbase), thus minimising the offshore time or field duration required for pipelay operations. A typical lay speed of some 12 km/day can be achieved, however the ship limited in pipe carrying capacity would necessitate multiple trips between the offshore field and the spoolbase to collect more pipe, or to replace the empty reel with a pre-loaded reel by means of heavy lift crane vessel. In this process the pipeline needs to be abandoned and recovered for each loading trip. The pipe is departing from the vessel in the near vertical position (as for the J-lay) and the pipe load is controlled by both tensioners (mounted on the J-lay ramp) and the storage reel.



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During pipelay, the pipe is unspooled from the reel and guided via an aligner to a straightener on the lay ramp. The pipe then passes through the straightener, down the ramp, through the tensioners and overboards the ship (see section 4.6). The main advantage of the reel lay method are high lay speed (i.e. short offshore operation time) but requires a near onshore spoolbase. The current reel lay method is limited in diameter and requires an optimum pipe thickness for reelability (i.e. D/t ratio in the range of 12 to 15). It is believed that reel lay capabilities will be extended as follows: •

2500 m for a 12" pipe with a wall thickness assumed of 31.8 mm

•

1500 m for a 16" pipe with a wall thickness assumed of 31.8 mm

The spooling and unspooling process will introduce an elasto-plastic bending with maximum cumulative strain in order of 2 % - 5% ranges. However there should not be any residual strain (unlike the 'Steep S-lay') as the straightener will exert a reverse bending moment which would result in a near zero residual curvature (see section 4.6).

4.4

S-Lay versus J-Lay

Table 3 summarises dynamic parameters (i.e. lay tensions, pipe stress and radius of curvature) obtained for the following conditions: • Waves:

significant wave height Hs: 1.5m average zero-crossing period Tz: 12s

• Heading:

0°

• Water Depth:

500m

• Lay ship:

typical 25000t displacement

• Pipe:

16", 14.3mm thick (Local buckling criteria, DNV 96) Minimum yield strength SMYS: 450Mpa

• Lay angle

70°

Effective Tension at vessel (kN)

Horizontal Tension at vessel (kN)

Mean

+/-

Mean

+/-

S-Lay

1050

200

820

150

J-Lay

310

30

90

20

Max. Equivalent Stress (MPa)

Radius of Curvature (m)

At stinger departure

At sag bend

At stinger departure

At sag bend

S-Lay

350

100

130

1200

J-Lay

20

200

-

250

Table 3 – Dynamic parameters summary table 1



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The maximum equivalent stress (von Mises expression) has been fixed to 350MPa (i.e. about 0.8 x SMYS) for both lay methods. The results bring the following remarks: • during S-lay, the stinger tip is a "sensible" location where the pipe endures high stress due to the vessel motions • higher horizontal tension to be retained by the vessel DP is required during S-lay to control the pipe departure angle at stinger tip • S-lay induces higher (than J-lay) tension and stress variations. The S-lay method is then limited by the vessel DP capabilities (which have to counteract the pipe horizontal tension) to water depths about 500-600m (depending on the pipe diameter); the J-lay method is then preferred for the following considerations: •

Minimum horizontal tension to be controlled by the DP system

•

Lower pipe stress by avoiding the transition from horizontal firing line to vertical position of pipeline at mid water depth

•

Better control of J-Lay sag-bend radius than S-lay stinger tip



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4.5


Steep S-Lay Strain

The following figure 1 illustrates the moment-curvature (n.b. pipe curvature is the inverse of the radius of curvature to which the pipe is bent) for elasto-plastic bending on a typical 'steep S' stinger. As the pipe enter the stinger, the moment increases and the curvature initially increases proportionally, indicating an elastic beam bending response (straight line OA). Once the yield point is passed, the response become non-linear following the path ABC as plastic ovalisation occurs. As the moment is decreased (i.e. pipe has passed the stinger tip) the pipe recovers along the path CDEF and the ovalisation decreases. At this point the elastic recovery will result in a residual curvature (or strain) shown by point G, when the pipe will rest on the seabed. To obtain a near zero residual strain, a reverse bend should be applied till point H is reached, prior to return to point O. However it is unpractical to install a straightener at the stinger tip.

Moment C

at stinger B A

Residual Curvature O G

D

Curvature

E H

F

off stinger

Figure 1 - Steep S-Lay moment-curvature relationship



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4.6


Reel-Lay Strain

The following figures 2- 4 illustrates the stresses and strains during a completed reel lay cycle :

•

as the pipe is spooled onto the reel beyond the yield stress, the elasto-plastic strain follow the path OA

•

as the stress is decreased during the first unspooled phase between the reel and the aligner, the pipe recovers along the path AB

•

when the pipe passes over the aligner curvature, a new stress-strain elastoplastic deformation is experienced along the path BCD

•

a new stress relief is obtained when the pipe passes between the aligner and the straightener, as per the path DE

•

finally a reverse bending is applied in the straightener (negative strain) until point F is reached, after which recovery should result in zero residual strain

As stated previously, the total cumulative strain experienced by the pipe will be in the 2%-5% range.

Stress

Stress spooling

A

aligner

O

O

C

Strain

B

unspooling

Spooling and unspooling

D

Strain

F

B, E

straightener

Aligning and straightening

Figure 2 - Reel Lay stress-strain relationship



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ALIGNER PIPE (upper layer)

PIPE (lower layer) STRAIGHTENER

REEL

Figure 3 - Straightening principle

Straightener

Reel

Tensioner Aligner

Figure 4 - Reel Lay equipment



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4.7


Deepwater J-Lay Parameters (Rigid pipe, Flexible & Umbilical)

This section summarises the rigid pipe, flexible and umbilical laying parameters for water depths from 1000m to 3000m.

4.7.1

Rigid Pipe

Pipes ranging from 6" to 16" (see table 4) are designed for the considered water depth range based on the hydrostatic pressure / local buckling criteria (i.e. buckle arrestors could be used): 1000m

1500m

2000m

2500m

3000m

Pipe 6"

8,7

9,5

11,0

12,7

14,3

Pipe 8"

11,1

12,7

14,3

15,9

18,3

Pipe 10"

12,7

15,9

18,3

18,3

20,6

Pipe 12"

15,9

17,5

19,1

22,2

23,8

Pipe 14"

15,9

19,1

20,6

23,8

27,0

Pipe 16"

19,1

20,6

23,8

27,0

30,2

Table 4 - API wall thickness (mm)

The following pipe effective tensions, horizontal tensions and pipe sag-bend radii have been determined for respectively 85° (see figure 5) and 87° (see figure 6) laying angle.



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Effective Tension vs Water Depth 6000

Effective Tension

5000

Sagbend Radius

effective tension (kN)

Horizontal Tension

85 °

dyn. coeff.: 1,2 approx. lay angle: 85°

4000

Pipe 6" Pipe 8" Pipe 10"

3000

Pipe 12" Pipe 14"

2000

Pipe 16"

1000 0 1000

1500

2000

2500

3000

water de pth (m)

Horizontal Tension vs Water Depth


500 450

horizontal tension (kN )

400 350 Pipe 6"

300

Pipe 8"

250

Pipe 10" Pipe 12"

200

Pipe 14" Pipe 16"

150 100 50 0 1000

1500

2000

2500

3000

water depth (m)

Sagbend Radius vs Water Depth 350


sagbend radius (m)

300 250

Pipe 6" Pipe 8"

200

Pipe 10" 150

Pipe 12" Pipe 14"

100

Pipe 16"

50 0 1000

1500

2000

2500

3000

water depth (m)

Figure 5 - Rigid pipe lay parameters (85° laying angle) Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Effective Tension vs Water Depth


6000 Effective Tension

5000 87 °

Sagbend Radius


Horizontal Tension

Pipe 6"

4000

Pipe 8" Pipe 10"

3000

Pipe 12" Pipe 14"

2000

Pipe 16"

1000 0 1000

1500

2000

2500

3000

water depth (m)

Horizontal Tension vs Water Depth dyn. coeff.: 1,2 approx. lay angle: 87°

300

horizontal tension (kN)

250 Pipe 6"

200

Pipe8" Pipe 10"

150

Pipe 12" Pipe 14"

100

Pipe 16"

50 0 1000

1500

2000

2500

3000

wate r de pth (m)

Sagbend Radius vs Water Depth


250

sagbend radius (m)

200

Pipe 6" Pipe 8"

150

Pipe 10" Pipe 12"

100

Pipe 14" Pipe 16"

50 0 1000

1500

2000

2500

3000

water depth (m)

Figure 6 - Rigid pipe lay parameters (87° laying angle) Note: The various laying parameters concerning the 16" rigid pipe are not indicated for water depths lower than 2000m as the bending moment at sag bend exceeds the allowable value. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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4.7.2


Flexible Lines

Vertical lay parameters have been defined for flexible lines ranging from 4" to 16" ID (see figure 6).

Effective Tension vs Water Depth


4000


3500 3000

4" Flexible 6" Flexible

2500


2000

12" Flexible

1500


1000 500 0 1000

1500

2000

2500

3000

water depth (m)


200

horizontal tension (kN)

180 160

4" Flexible

140

6" Flexible

120

8" Flexible

100

10" Flexible

80


60

16" Flexible

40 20 0 1000

1500

2000

2500

3000

water depth (m)

Figure 6 - Flexible lay parameters (87° laying angle)

Note : For large diameter flexible, the lay tension are water depth limited due to the flexible product limitation: 12” (3000m), 14” (2000m) and 16” (1600m).



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4.7.3


Umbilical Lines

Vertical lay parameters have been defined for umbilicals ranging from 114mm to 180mm OD (see figure 7).

Effective Tension vs Water Depth dyn. coeff.: 1,2 approx. lay angle: 87°

2000 1800 effective tension (kN)

1600 1400 114mm OD Umbilical

1200

138mm OD Umbilical

1000

146mm OD Umbilical

800

180mm OD Umbilical

600 400 200 0 1000

1500

2000

2500

3000

water depth (m)


100 90 horizontal tension (kN)

80 70 114mm OD Umbilical

60

138mm OD Umbilical

50

146mm OD Umbilical

40

180mm OD Umbilical

30 20 10 0 1000

1500

2000

2500

3000

water depth (m)

Figure 7 - Umbilical lay parameters (87° laying angle)



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4.8


Installation Method Limitations

The following table 5 will summarize the limitations of each sealine technology versus the installation techniques: SEALINES

INSTALLATION METHODS AND LIMITATIONS S-Lay (Steep)

1. Wet Insulated Pipe • Medium size flowline • Residual plastic deformation at stinger departure

J-Lay

Reel-Lay

• No known limitation • Medium size besides the lay rate flowline with D/t ratio within 16-24 for reelability • Cumulative strain deformation

• Water depth limitation

• Water depth limitation

(e.g. 2000m)

(e.g. 2500m)

2. Flexible pipe

• Not applicable

• Could be defined as vertical lay

• Flexible flowline can be reeled and lay with the ramp tensioners

• Limitation is related to the flexible technology • Limitation on product technology

3. Clad pipe

• Same limitation as • No known for 1.above (see limitation besides note) the lay rate

• Not recommended

4. Pipe-in-pipe

• Same limitation as • Will require for 1.above bulkheads

• Bulkheads to be replaced by spacers for reelability

• Lay rate

• Same limitation as for 1. above

Table 5 – Installation methods and limitations versus sealine technology

Note: At report date, Allseas Solitaire DP Vessel has been awarded the Shell Malampaya pipelay which includes a 16” diameter carbon steel incoloy 825 clad pipe at 850m WD.



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5


DYNAMIC POSITIONING EQUIPMENT & CLASS

5.1

General

The DP system, encompassing all equipment, sub-systems, control, power, engines, thruster, etc, that directly or indirectly effects the position keeping ability of the vessel, must be designed with built-in redundancy and reliability to meet with or exceed the DP System Class 2 requirement. All components in a DP system should be designed, constructed and tested in accordance with international standards recognized by the International Marine Contractor Association (IMCA). For DP equipment class 2, loss of position shall not occur from a single fault of an active component or system such as generators, thruster, switchboards, remote controlled valves, etc, or from a single inadvertent act by any person on board the DP vessel (but may occur after failure of a static component such as cables, piping, manual valves, etc.). For DP equipment class 3, loss of position should not occur from any single failure (as for DP class 2 above) including any static component, and a completely burnt fire sub-division or flood watertight compartment. For equipment class 2 and 3, redundancy of all active components is required. The following sections define the basic and minimum requirements of the DP system.

5.2

DP Functional Requirement

5.2.1

Introduction

A fully operational dynamic positioning system shall reliably keep a vessel in pre-determined positions or tracks, such that the maximum excursion from vessel motions (e.g. surge, sway, yaw) and position control system accuracy shall be less than the critical excursion for the work being performed : •

when working alongside other vessel or nearby structures (fixed or floating)

•

during subsea structure installation

•

during laying operation while providing a steady tension on product

•

during connection of subsea components/structures

•

during Remote Operated Vehicle interventions

The DP systems comprise three areas defined as Power, Control and References : •

Power can be sub-divided into power generation, distribution and consumption

•

Control refers to an automatic power management system and the position control system

•

References are essentially sensors giving position, environmental and vessel attitude information (e.g. roll, pitch, heave, heading, etc).

Redundant components and systems must be immediately available and with such capacity that the DP operation can be continued for such a period that the work in progress can be terminated safely. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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5.2.2


Power System

The power system must have an adequate response time to power demand changes and be divisible into two or more systems such that in the event of failure of one system at least one other system will remain in operation. The power available for position keeping must be sufficient to maintain the vessel in position after worst case failure defined according to equipment class (refer also to section 4.4 Safety Requirement for definition of 'worst case failure'). Utilities supporting power generation systems e.g. cooling water, fuel oil, lubricating oil must be arranged so that their failure consequences are less critical than failure of the equipment they support. Power management is essential on all DP vessels. DP vessels which use substantial amounts of power for other equipment (than thrusters) such as cranes, lay equipment, accommodation, pumps, etc., must have the possibility to shed load to maintain power to thrusters. The electrical power distribution to thrusters is usually the aspect which determines the worst case failure mode. The control system must maintain enough power to give time to safely cease any operation for which position is critically important.

5.2.3

Thruster System

The thruster system should provide adequate thrust in longitudinal and lateral directions, and provide yawing moment for heading control. The thruster units should be arranged to give, as far as possible, a balanced configuration even after the worst case failure. A fail safe design must avoid a thruster control fault, that results in uncontrolled thrust which can destabilize the whole system.

5.2.4

DP References and Control System

5.2.4.1 References The position references have two functions, these are to provide (i) stable position information and (ii) sufficiently accurate positioning data for the work being carried out. For DP operations at least two (2) independent references should be on line and of different types (e.g. DGPS, hydro-acoustic, radio or surface positioning). When using similar reference sensors, they should be checked for complete redundancy and without common failure modes. The position reference systems on-line to the DP control should provide the DP operator with information to assist with decision making about individual reference system performance and malfunction. Typical reference accuracy are summarised as follows: •

DGPS:

•

Hydro-acoustic short baseline: within 2% of water depth with super-short

within +/- 3m (SSBL) or ultra-short (USBL) baseline system

•

Hydro-acoustic long baseline :

better than +/- 5cm over a 50m length (i.e. spoolpiece metrology)



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5.2.4.2 Control System The DP control system should provide adequate information to operators such that any change of status due to weather, equipment malfunction, or operator action shall be clearly indicated in the DP control room where corrective action is possible. For product laying, the tension control equipment, must be considered as part of the position control system, and designed with the same philosophy and level of redundancy to achieve a balanced vessel design. To assist the DP operator, the control system should have a continuous analysis function checking that in terms of thruster and power the vessel can maintain position after the worst case failure mode. 5.2.4.3 System arrangement The minimum requirements for of DP Equipment Class 2 system arrangement are summarised in the following table 6:

Power System

Sub-system or

Min. Requirement

Min. Requirement

Component

Class 2

Class 3

Redundant

Redundant separate compartments

1 with bus-tie

2 with normally open bus ties in separate compartments

1

2

Distribution system

Redundant system

Redundant through separate compartments

Power management

Yes

Yes

Redundant system

Redundant in separate compartments

Generators and prime movers Main switchboard

Bus-tie breaker

Thrusters

Arrangement of thrusters

Control

Auto control ; Number of computer systems

2

2 + 1 in alternate control station

Manual control ; joystick with auto heading

Yes

Yes

Single levers for each thruster

Yes

Yes

Position reference systems

3

3 whereof 1 in alternate control station

External sensors

Wind

2

2

Vertical Reference Sensor

2

2

Gyro compass

2

3

Other necessary sensors

2

2

Sensors

Uninterrupted Power Supply Alternate control station

Whereof 1 in alternate control station

1

1+1 in separate compartment

Yes

Yes

for back-up unit

Table 6 - System arrangement (DnV DYNPOS Class notation) Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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5.3


DP Capability Definition (& Plots)

For each dedicated Installation Vessel a ship theoretical capability plots must be produced, all in accordance with DPVOA document IMCA M 140, Specification for DP capability plots for the following cases (see figure 8): •

all thrusters operational with 100 % maximum effective thrust

•

all thrusters, except the most effective thruster failure

•

the maximum number of thrusters that could be operational after the worst case failure

Figure 8 – DP Footprint The above should be presented in polar plot form for various current speeds, i.e. 0, 1, 2 and 3 knots, co-incident with wind and associated wave loads from a fully developed sea. A realistic allowance shall be made for thrust losses from, interaction, tunnel length, control system response, etc. The purpose is to provide the DP operators with information so that they can assess whether safe working limits have been exceeded from intact power and thrust usage. For product laying operations, the DP capability plots shall be provided after the subtraction of the mean tension required for the highest pipe tension load combination (of heaviest pipe, deepest water, etc).



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5.4


Safety Requirement

5.4.1

Introduction

DP safe working limits must be determined for each geographical location and type of task to be performed. As a minimum, two types of risk assessment shall be performed : •

Failure Modes Effects & Criticality Analysis, which are equipment specific (e.g. DP Systems, laying & installation equipment, etc)

•

HAZOP/HAZID Analysis, which are more "Job" specific

5.4.2

DP System FMECA

When working closed to a fixed structure (e.g. FPSO) i.e. within the 500 m safety zone, the environmental limits (i.e. wind, waves, current, respective headings), where the DP vessel can maintain position after the worst case failure that are known to be possible, must be defined. This worst case failure is to be identified from a formal FMECA study, where all possible failure modes and effects are considered; to ensure that after the worst case failure, the vessel has sufficient capability to remain on position within safe limits from the FPSO (or other structures).

5.4.3

Hazardous Operation Analysis

In addition to the above formal DP vessel FMECA study, each location and task require documentation that further specifies any additional constraints in the form of HAZOP/HAZID analysis based on pre-established operation procedures (loading, transportation, laying, lifting, installation, testing, etc). The principle here is that each task is given individual consideration prior to its being performed. For product laying, the DP safe working limits must take into account : •

the consequences of sudden failure of the tension load (e.g. tensioner failure)

•

limits of heading capability in beam environmental conditions



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6


INSTALLATION AND LAYING EQUIPMENT DESCRIPTION

6.1

General

The equipment required on board the installation vessel for the laying of flexible lines, umbilical cables, rigid or reeled pipe are summarized in the following two tables 7 and 8: STORAGE FACILITY Carousel

Dolly base

Vertical Powered Reel

Horizontal Powered Reel

X

X

X

X

X

X

X

X

X

X

P Flexible

Rack

R line O Umbilical cable D U Reeled Pipe C T X

Rigid pipe Table 7 – List of product storage facility

INSTALLATION EQUIPMENT Vertical Lay Spread

P Flexible

J-Lay Ramp & J-Lay Ramp & Hang-off Tensioners Collar

Tensioners & High Departure Stinger

Tensioners & Lay chute

X

X

X

X

X

X

R line O Umbilical cable D

X

U Reeled Pipe C

X

T X

Rigid pipe

X

X

Table 8 – List of installation equipment

Typical load capacity and general description of the above equipment are presented in the following sections. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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With regard to lifting equipment, two cases must be considered: •

Topside lift with heavy lift crane barge

•

Subsea lift with adequate cable length and load capacities from a deck winch or crane

As stated in chapter 2, the offshore topside heavy lift industry is well established and hence this topic does not require any further comments. For the subsea lift, holding a subsea structure weighing some 300T plus the lifting cable own weight of 130T (i.e. cable wire of OD 122mm, with linear weight of 65kg/m at 2000m water depth) will impose loads that a standard winch cannot cope with. New handling equipment such as linear winches or capstan winches must be designed with the use of lighter cable (e.g. synthetic rope) with anti-twist property to fulfil the requirement of deepwater lifting and lowering of subsea structures. (section 6.4 Abandonment and Recovery equipment)

6.2

Storage Equipment

6.2.1

Basket Storage Carousel

The basket storage carousel is an horizontal storing system designed to accommodate flexible line up to 16-inch and umbilical cable (see figure 9).

Spooling arm

Flexible end termination Carousel

Figure 9 – Carousel on CSO Sunrise 2000 It comprises a structure which will rotate on a vertical axis, and which is supported and run on typically double circular roller track. Rotation is achieved by a chain transmission fixed to the outer periphery of the carousel base. There is also a central king pin for centralization.



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The main components of a basket storage carousel system are listed below: • • • • • •

carousel structure transmission drive AC motor drive controller unit supporting roller groups & king pin spooling arm and chute system control equipment

The basket storage carousel is equipped with an articulated spooling arm & chute system to correctly spool in the pipe during the load-out and extract the pipe from the basket during laydown operations. Typical technical specifications of a 1600T basket carousel system are described below: • • • • • • • 6.2.2

1600T total product capacity 200T - 250T empty carousel weight 17m base or outside diameter 4m inside diameter 7m inside height 7m maximum product height 0-900m/hr laying speed

Horizontal Powered Reel

The horizontal powered reel is designed as a reel system dedicated to load and lay large quantities of flexibles, small diameter pipelines or umbilical, in particular integrated services umbilical (see figure 10).

Spooling system

Horizontal powered reel

Umbilical

Aligner

Figure 10 – Umbilical loading on horizontal powered reel (Seaway Condor) The horizontal powered reel is also used to lay reeled rigid pipe from a reel lay vessel on which it is installed temporary or permanently.



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The horizontal powered reel comprises one rotating vertical axis reel around which the product is stored using laying ramp and straightener/spooler system which is mounted on the deck for the control of the spooling operation. During spooling, the pipe string passes up the ramp and then wraps around the reel in a counter-clockwise direction. Before being wrapped around the reel, the pipe passes over an alignment shoe that adjusts vertically allowing the pipe to level wind onto the reel. The process is reversed during installation. A straightener mounted aft of the aligner is used during installation of rigid lines (reeled pipe, rigid umbilical, integrated service/production umbilical) to remove any residual pipe curvature resulting from the reeling process. Note that the aligner is designed to bend the pipeline in the reverse direction before it enters the straightener. By reversing the pipe curvature, it ensures that the residual curvature of the pipe entering the straightener is constant and independent of the amount of pipe remaining on the reel. Rotation of the reel supported by a base frame with a double circular roller track is achieved by a chain transmission fixed to the outer periphery of the lower reel flange. The replacement of the drive chain by a flame cut ring gear and pinion is an alternative solution to increase reel tension. There is also a central king pin for centralization. The system consists of the following main components: • • • • • • •

base frame horizontal reel structure transmission drive AC motor drive controller unit supporting roller groups & king pin straightener/spooler control cabin

Typical technical specifications of a 1000T horizontal reel system are described below: • • • • • • •

1000T total product capacity 170T-200T empty powered reel weight 12m base or outside diameter 5m inside diameter 5m inside height 6m external height 0-1800 m/hr loading speed, 0-900 m/hr laying speed



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6.2.3


Vertical Powered Reel

There are two types of vertical powered reel depending on the product to be laid: y Flexible and umbilical powered reel y Rigid pipe powered reel

6.2.3.1 Flexible and Umbilical Powered Reel The flexible and umbilical powered reel is a portable reel system designed for the purpose of installation or recovery of flexible pipelines and umbilicals (see figure 10). The powered reel system has a specific product capacity and is designed to withstand the dynamic forces resulting from storm conditions while carrying this load.

Vertical reel Drive tower

Flexible

Level winder

Figure 10 – Flexible unloading from vertical powered reel The powered reel can be split into two drive towers and the interchangeable drum. The lift beam is capable of lifting the base and reel together or separately. It is worth noting that this system can be used for spooling of small pipeline or coil tubing. The powered reel system is composed of: • base frame • winch system • reel • AC motor drive controllers box • control equipment • level winder.



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A typical 300T powered reel system main characteristics are as following: • • • • •

Powered reel system empty weight Maximum product capacity: Total footprint area (including reel): Base frame footprint area: Reel dimensions :

70T 300T 13m x 8.7m 13m x 5m 8.7m flange diameter 4.8m hub diameter 5m width

•

Torque ratings:

60T.m at 1 rpm 12T.m at 10 rpm

6.2.3.2 Rigid Pipe Powered Reel The rigid pipe powered reel consists in one large reel of specific product capacity and permanently installed on board the laying vessel (see figure 11). Reeled pipe

Vertical powered reel

Lay ramp

Figure 11 – Vertical powered reel for reeled pipe (ETPM Norlift) The pipe laying tension is entirely controlled by the tensioning system within the J-Lay ramp where the storage reel only takes the minimum back tension required for correct spooling of the pipe onto the reel. When laying pipe, the reel is running in "drag mode", the reel torque is adjusted accordingly to the required tension. When spooling on pipe, during loadout operation, the reel is running in traction mode and the reel torque is adjusted according to the required back tension of the pipe stack. A 5000T reel storage dimensions are as follows: • • • • • • • • • •

Flanges outside diameter Drum outside diameter Width Maximum pipe pay load Storage volume Packing density Spool in/out speed Spool back tension Drive system Reel bearing


34m 18.5m 8m 5000Te 5113m3 0.98Te/m3 30m/mn at any layer 50Te Hydraulic drive + rack & pinion Shaft bearing


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6.2.4


Dolly Base

The Dolly Base is used for the purpose of unreeling flexible or umbilical lines during laying operation (see figure 12). In this mode a tensioner is required for maintaining the line tension. Control container Rollers

Motorized rollers

Support frame

Figure 12 – Dolly base The dolly base could be used for spooling the flexible lines onto the reel. A level winder can be provided to control the fleet angle of the flexible during spooling. It is composed of a base frame supporting four (4) rollers. The dolly base has a SWL capacity equal to reel plus product weight and can withstand the dynamic forces due to vessel motions. The dolly base system is composed of: • • • • • •

base framework drive system AC motor drive controllers box control console set of seafastening devices lifting beam and sling set.

A typical 270T dolly bases features: • Total design loading (product plus reel) : 270T • Base frame footprint:

8.4m x 7.3m

• Dolly base total weight:

30T

• Line pull: 3T - 5T with a spooling speed of up to 1800 m/hr



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6.3


Laying Equipment

6.3.1

Tensioner

A typical tensioner, designed to hold back tension induced by weight of heavy products during installation phase, is composed of three or four track units mounted in a steel frame and driven by either electrical or hydraulic power system (see figure 13). Clamping cylinder

Track unit

Pads

Support frame

Figure 13 – 3 tracks tensioner The track units, able to spread the clamping force over the circumference of the line, provide an even compression load over the full contact length. The current typical tensioner contact length is in the range of 1200mm to 3500mm (per track unit). Each of the track unit includes caterpillar chain and low friction chain rollers, and contains all tensioner functions which are: • • • •

Chain drive Clamping function Opening function to allow passage of end fittings Load cell for tension monitoring

These track units are mounted in a closed frame, which can occasionally be opened to allow passage of large objects. The tensioner can be controlled either in speed mode or in tension mode. In the first case the tensioner maintains a certain speed which is dependent on the tension value. The tensioner can also be given a tension set-point. In this case the unit maintains a certain amount of tension independently of the speed. The typical technical specifications of a 135 Te tensioner are as follows: • • •

Dimensions Weight Laying speed


6.2m x 6.2m x 7.6m 105Te 0-15m/min at 125Te 7.5m/min at 135Te


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6.3.2


Overboarding Chute

The minimum radius overboarding chute (i.e. 6m to 12m radius) aims to control the line curvature and to allow a safe overboarding of umbilicals (steel umbilical or integrated service umbilical) and flexible flowlines (see figure 14).

Overboarding chute

Figure 14 – 12m radius overboarding chute (Seaway Condor) When fitted with a low friction chain, it permits safe transfer of lines from the horizontal position to the vertical position. The overboarding chute frame is fixed on the side or at the stern of the laying vessel.



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6.3.3


High Departure Angle Stinger (rigid pipe laying)

The physical characteristics of this stinger are significantly different from stinger traditionally used in shallow to moderate water depths. The deepwater stinger found mainly in steep S lay method provides (see figure 15): y A near vertical departure angle for true J-lay with a low horizontal tension y A fixed truss design rigidly connected to the barge to reduce pipe strains in the overbend y 2-piece construction stinger with a removable tip section for vertical pipelay y Closely spaced supports to limit pipe strains due to local bending on the supports.

Steep S stinger

Tensioner

Horizontal powered reel Pipe

Tip

Straightener/ Spooler

section

Figure 15 – Stinger for Steep S lay method on HERCULES (GLOBAL IND.) The stinger is rigidly attached to the lay barge with an angle of approximately 45 degrees, instead of being hinged and free floating like a conventional stinger, because it must support the large pipe loads produced by the steep departure angle and high pipe tension required in deep waters. It is not practical to build a floating structure that is capable of supporting these loads. The rigidly attached stinger also provides greater control of the pipe curvature in the overbend. Because its position is fixed relative to the barge, it can use a smaller radius of curvature and still achieve the same actual maximum pipe strain in the overbend as the hinged floating stinger with a larger radius and greater length. The high departure angle stinger is constructed in two pieces. The first, larger section is approximately 34m in length. At its minimum 42m radius, this section provides a departure angle of approximately 65 degrees and can be used alone to lay pipelines up to 6-inch in diameter in water depths from 610m to 915m. A second, removable tip section can be used to provide a near vertical (90 degree) departure angle for stabbing directly into subsea connectors. The stinger has a variable radius with a range of adjustment of approximately 42m to 68m. This range of radii accomodates pipe diameters up to 12-inch. To minimize the stinger length and maximize the departure angle, the stinger is designed to use a smaller radius of curvature and produce higher bending strains in the overbend than the conventional stingers utilized in shallow water. Its 42m minimum radius corresponds to a nominal bending strain of Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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0.2 percent for 6-inch pipe. Pipe strains of this magnitude can be accommodated by the high yield strength, low D/t ratio pipelines laid in deep waters. To keep the pipe strains on the stinger as low as possible, the pipe is supported in the overbend by a series of closely spaced pipe supports which have an average separation between rollers of less than 1.5m.

6.3.4

Flexible and Rigid Pipe J-lay Ramp

The J-Lay ramp, installed on the lay vessel, is designed for the installation of rigid and flexible lines in deepwater using the J-Lay method (see figure 16).

Travelling assembly Travelling assembly

Gutter Gutter J Lay tower Tilting system Tensioners

Loading arm

Pipe string Working platform

Hang off clamp A & R winch Active roller box

Figure 16 – Flexible and rigid pipe J-lay ramp (SAIBOS FDS) The main requirements for a typical 2000m water depth J-Lay ramp are listed below: • • • • •

Design load Rigid pipe range Pipe string range Flexible pipe range Special items (PLEM)


400 tons SWL 4’’ - 18’’ (external diameter) 41,6 - 52m (overall length) 2’’ - 17’’ (internal diameter) 6m x 3m x 3m (maximum dimensions)


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The J-Lay Ramp System includes the following main assemblies and subassemblies : • J-Lay tower used as a foundation for the equipment required for laying flexible and rigid lines. The J-Lay tower is connected to the vessel main deck with a hinged connection at the lower end • Tilting system served to raise the tower at a particular angle from 45° to 96° in working conditions and to store the tower in lowest position (e.g. 12°) in survival conditions • Travelling assembly, running on a double guides and designed to lower pipe string handled by a hydraulic elevator upon completion of welding process. This assembly will also integrate the Internal Line-Up Clamp and X-Ray Tube with its umbilical winch • Tensioners (3 off) mounted on sliding ramp will be moved from their storage position to pipeline lay axis for flexible lay operation • Retractable gutter, located at mid height of the J-Lay tower and mounted on skid, will be moved in position for flexible lay operations • Retractable A&R sheave for abandonment and recovery of lines will be positioned on the loading arm in such a way that it will be above the PLEM upper position when the loading arm is upended in the J-Lay tower • Working platform located at the base of the J-Lay tower to support assembling station and welding equipment • Hang off clamp for both flexible and rigid pipe, positioned at the working platform, to hang the pipeline during welding operation • Active roller box system composed of upper and lower guiding roller sets to control pipe departure movements • Loading arm system to transfer pipe string from horizontal position at the firing line or storage area to various position of the J-lay tower. In addition the loading arm includes a line-up device for the performance of pipeline alignment prior to welding.



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6.3.5


Flexible and Reeled Pipe J-Lay Ramp

The flexible and reeled J-lay ramp is a pipelay system capable of laying both rigid and flexible pipe including piggyback rigid pipe or umbilicals (see figure 17). The system is also able to accommodate attachment and deployment of pipeline components such as flanges, anodes and buoyancy elements. The pipelay system comprises a 30m ramp, which is elevated from 20° to 90°. The ramp can traverse 3 meters thereby negating the requirement for a spooling system on reel.

Main and

Welding station

Piggy back chutes Tensioner and straightener

Exit roller box

Vertical reel

and monitoring system

Level wind

Figure 17 – Flexible and reeled pipe lay ramp (CSO APACHE) Situated on the ramp are: y Main chute y Piggy back chute y Main and Piggyback straightener y 120Te tensioner y Pipe alignment cylinders y 200Te hang-off clamp y A&R sheaves y Exit roller box y Exit monitoring system The ramp pipelay system is controlled and operated from a central control station located in the Pipe Lay Control Cabin.



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6.3.6


Rigid Pipe J-Lay Ramp

The rigid J-lay ramp equipment comprises 2 main modules: an upending ramp for the preassembled 72m pipe strings; and a variable angle stinger which contains the line-up tools, welding/inspection/coating station and pipe tensioners. The system is generally mounted over the stern of the semi-submersible crane vessel (SSCV) (see figure 17).

Upending ramp Stinger Line up tool Tensioners Welding station Coating station

Pipe departure

Figure 17 – Rigid pipe J-lay ramp The major system components are described hereunder: y Upend ramp: This 110m long ramp upends the 72m long pipe strings from horizontal to the stinger angle by means of a tackle system located at the top of the stinger. The upend ramp also supports the line-up tool which is hung down inside the pipe. y Stinger: This is hinged over the stern of the vessel and its angle can vary from 20 to 100 degrees. It contains the line-up tools, welding/inspection/coating station, pipe tensioners and monitors. y Line-up tool: The external line up tool serves to take over the 72m pipe string from the pipe ramp after upending, then lower the pipe string to meet with the pipe line, and provide a provisional line-up between the pipe string and the pipe line. Final line up is achieved by means of an internal line-up tool. y Weld station: The weld station is located in the upper section of the stinger. It is mounted on a tilting platform to accommodate the J-lay range of inclinations. This platform provides floor space for the crew for line-up, welding and NDT. It also supports all equipment required for pipe line-up, re-beveling, welding and nondestructive testing. The station is weather protected.



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y Control cabin: The control cabin is located on the tilting platform. y Pipe departure angle survey system: For monitoring the stinger inclination and vessel heading with the direction of pipe departure, four rollers are provided at the very lower end of the stinger. They follow the pipe movements and provide information on pipe position. y Pipe departure support rollers: Series of rollers in a trumpet like arrangement is provided at the bottom end of the stinger.

6.3.7

J-lay Ramp using Hang-Off Collar

The following is a brief description of the major components of the four pipe strings J-lay system using hang-off collar (see figure 18) :

Travel block Pipe bin unloading cranes

Working

Strongback

station Tower

Stinger

A-frame Pipe departure

Pedestal

Figure 18 – J-lay ramp using hang-off collar (J-Ray McDermott DB50) y A-frame and Foundation: This is a single piece module whose function is to provide support to the other major components of the J-lay system. Composed of tubular framing supported by three (3) large boxed girders, the A-frame and foundation extends over the starboard side of the lay vessel approximately 10m enabling the pipeline centerline to be located outboard of the lay vessel for J-lay operations. y Tower support structure: The tower support structure pins to padeyes located forward and aft of the stern and middle boxed girders in the foundation. Padeyes located on the tower support structure allow the J-lay system tower and stinger to be attached above and below the tower support structure respectively. A series of padeyes arranged vertically on the middle boxed foundation girder allow the tower support structure, tower and stinger acting as a unit to be adjusted over a range of 70 to 90 degrees relative to the horizontal.



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y Tower: Pinned at its base to the tower support structure, the tower provides the structural support for the major J-lay system pipe joint handling and pipeline lowering components. The tower provides guide rails for the raising and lowering of the strongback and travel block. Located at the base of the tower is the fully enclosed work area where all welding, NDT and field joint coating operations are conducted. Located on top of the 61m tower are a set of sheave assemblies facilitating the routing of the rigging utilized for pipeline abandonment and recovery operations. y Stinger: Pinned to the tower support structure, the stinger extends approximately 15m below the water surface and supports three (3) hydraulically operated, retractable full encirclement roller assemblies designed to support the upper portion of the pipeline during pipeline welding operations. Video cameras located adjacent to each stinger roller assembly assist the J-lay system operators to sequentially open and close each roller assembly in order to facilitate the passage of the J-lay collars and anodes during pipeline lowering operations. Five additional underwater video cameras located at the lower elevation of the stinger provide the means by which engineering personnel can visually observe and measure pipeline deflections required to maintain pipeline bending strains within allowable limits. The lower portion of the stinger is also designed to be retracted by extending two large hydraulic cylinders mounted to the upper (or fixed) portion of the stinger framing in order to facilitate pipeline abandonment and recovery operations y Ready rack: The ready rack, located immediately astern of the A-frame and foundation and centered on the pipeline centerline, provides guide rails for the strongback that tie-in by means of interchangeable tower angle transition rails to the strongback guide rails located in the tower. Four retractable horizontal roller assemblies located on the ready rack support each quadruple joint prior to being elevated into the tower for welding operations. y Strongback: Designed to travel along the guide rails located in the ready rack and tower by means of double roller assemblies located fore and aft, the strongback provides the means by which each quadruple joint is raised from the ready rack up into the tower for pipeline alignment and welding operations. Measuring approximately 51m, the strongback is equipped with four hydraulically operated multi-purpose pipe handling clamps designed to retrieve each quadruple joint while in the horizontal position from the ready rack and to assist in welding alignment operations when supporting quadruple joints in the vertical or nearvertical position in the tower. y Strongback lowering cylinders: They support the strongback while the strongback is in the vertical or near-vertical position and provide the means by which each quadruple joint is adjusted vertically for welding alignment operations. y Pedestal: The pedestal is located on two retractable support frames mounted on the tower support structure immediately below the floor of the work area. The pedestal of four vertical lugs which engage the underside of the J-lay collar flange, thereby providing the means by which the pipeline is supported below the field joint during welding, NDT and field joint coating operations. The pedestal is designed to be retracted away from the pipeline centerline in order to facilitate passage of the J-Lay collar and anodes during pipeline lowering operations.



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y Travel block: Designed to travel along the guide rails located in the tower, the travel block is an open face split block designed to engage the under side of the Jlay collar flange and is used to lower each quadruple joint onto the pedestal after welding and NDT operations are completed. The travel block houses two four-inch thick retractable slide plates which, when closed together under the flange of the J-lay collar, support the entire weight of the pipeline during lowering operations.

6.3.8

Flexible Vertical Laying System

The flexible vertical laying system is specially designed to install large diameter flexible pipelines in deep waters (see figure 19). The spread is installed at the stern or over a moonpool of the lay vessel, and is composed of the following stacked elements: y A working table, above sea level y Several modules of tensioner, installed over the table on a foundation structure y An upper module supporting a pipe deflector (gutter), a 10t service crane and the load transfer system (A & R Winch) Transfer crane

A & R winch

Gutter

Tensioner

Flexible

Working platform

Figure 19 – Vertical Laying System (CSO FLEX INSTALLER) The working table is designed to support the full catenary load and is composed of hydraulically operated movable parts and can clamp the line fitting and hold the catenary tension allowing the connection of two line sections or special items such as PLEM in a vertical configuration. The system also allows the passage of pre-installed intermediate connections and the opening of the table for the passage of large pre-installed accessories. The top module transfer system, permits the holding of the tension of the line and transfer of the end fitting throughout the tensioners, whilst they are open. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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A safety collar is available for securing the line tension at the working table in the event of a major tensioner break down. Several multipurpose tugger winches are available in the working table area. The vertical laying spread is operated from the deck operation control room. The technical specifications of a 270T flexible vertical laying system for 2000m water depth are presented hereunder: y Maximum pull: y Maximum brake capacity

375T

y Passage through tensioner

1200mm

y Minimum flexible line diameter y Maximum flexible line diameter

80mm

y Laying speed

0 to 16m/min


270T

600mm


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6.4 6.4.1


Abandonment and Recovery Winch General

For deepwater lowering and recovery operations (e.g; beyond 1000 - 1500 msw) the standard powered winches with steel wire cable are not adapted due to the high load requirement of some 400 tons capacity. Three alternative A&R winches are being used with its own advantages and disadvantages :

6.4.2

y

linear traction winch with steel wire cable stored on a separated reel

y y

capstan friction winch with cable stored on a separated reel 'flexible pipe follower' using existing flexible pipe tensioner device and stored on dedicated powered reel

Linear Traction Winch

The adequate length of steel wire are stored on a large powered reel, with the load tension provided by a linear winch. The linear winch features double jaw devices, one static and one moveable part activated by hydraulic rams providing a step-by-step displacement of the steel wire cable at each stroke (see figure 20).

Jacking cylinders

2 half grippers

Support frame

Figure 20 – Linear winch

This technique which can provide very high tension (more than 1000 tons) has a major drawback related to its very low lowering speed and is therefore used only for installation of very large subsea templates or foundation structures.



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6.4.3


Capstan Friction Winch

As for the above, the steel wire cable are stored on a separated reel with the load tension provided by a double-drum capstan friction winch (see figure 21). Capstan winch

Cable storage winch

Figure 21 – Capstan friction winch This technique will provide sufficient abandonment and recovery speed (e.g. 900 m/h) with however a major drawback related to the residual torsion induced on the steel wire (passing through the double drum capstan winch) which would twist the cable as the lifted load is disconnected from it. Unless the steel wire is prevented from twisting, permanent damage will be experienced. Capstan friction winches used in combination with steel wire of some 4"1/5 OD (440 tons SWL) are currently limited to the water depth of 1000-1500 m. It is believed that this water depth can be extended with the use of synthetic rope (e.g. high modulus polyethylene 'Dyneema'), however adequate friction between the synthetic rope and the capstan steel drums must be ensured. Synthetic rope has a major advantage in terms of weight, as its density is approximately 1.07, however there is concern with regards to (1) termination eye spliced, (2) tension fatigue and (3) tension capacity reduction due to creeping and ageing. 6.4.4

Flexible Pipe Follower

In Brazil for deepwater A&R operations down to 2500 m, Coflexip has promoted a different technique known as the 'pipe follower' where a 6"OD flexible pipe is used with the existing tensioner system, to lower or recover a load (see figure 22). VLS (Vertical Laying System)

Dolly bases loaded with flexibles

Figure 22 – Laying vessel in “pipe follower” configuration The main drawback is that this technique can be used only from a dedicated deepwater flexible lay spread. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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6.5 6.5.1


Welding and Tie-in Techniques General

The essential feature in offshore pipelaying is that economic pipe string production for a sufficient pipelay rate can be achieved only by partitioning the welding procedure in a series of single jobs at multiple welding stations using one or a combination of the following conventional processes : y Shielded Metal Arc Welding (SMAW) y Gas Metal Arc Welding (GMAW) y Gas Tungsten Arc Welding (GTAW) Since the laying of pipelines in deep and ultra deep waters using the J-lay method requires single station welding, a long welding time would be needed to perform the entire weld at a single station using conventional techniques for pipe wall thickness up to 40mm. This problem has led to the development of a system of fast welding at a single station. Several welding processes (currently still at R&D stage) are to be considered: y Electron beam welding y Flash butt welding y Radial friction welding y Laser welding For small diameters (up to 10" – 12"), the rates obtained with threaded pipes or by a conventional welding method can be used at a pace that J-curve laying technique is economically feasible. However, as regards the joining of heavy walled (1" to 2"), large diameter (12" to 36") pipes, the problem becomes totally different since the high rate of laying (1 joint every 15minutes) required for economic reasons can only be reached if the welding operation is carried out in less than 5 minutes. None of the conventional welding processes can produce this type of weld in such a short time.



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6.5.2


Conventional Welding Technique

For conventional offshore or onshore pipelaying, manual arc welding by means of cellulose covered electrodes (SMAW) is fully service-proven (see figure 23).

Figure 23 – Manual welding Mechanized shielded arc welding methods have been developed which have largely replaced manual welding with cellulose electrodes in offshore pipelaying because of improved weld quality and efficiency. The estimated manual welding times for various pipe diameters are depicted in Table 9 for a constant D/t ratio of 20: PIPE OUTSIDE DIAMETER

WELD TIME

(inches)

(minutes)

8.625

11

10.750

20

12.750

24

14.000

33

16.000

49

20.000

75

24.000

130

Table 9 – Manual welding time

Note: Time estimated excludes inspection and coating and allows for increasing number of welders as diameter permits.



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As shown, the time required increases rapidly for diameters greater than 16-inches. Material grade is also a factor in total welding time. Pipe wall thickness up to 1-inch for API 5L X65 (1.25-inch for X60 and 1.375 for X52) are expected to be suitable for welding with normal weld control procedures. Greater wall thickness will require specialised metallurgy control. If the necessary pipe metallurgy cannot be achieved and post heat treatment becomes a requirement, a severe time penalty will be imposed. The heat must be maintained for a length of time sufficient to allow diffusion of hydrogen and elimination of Martensite. Indicative of industry practice is one hour of post weld heat treatment per inch of wall thickness. The estimated mechanised welding times for various pipe diameters are depicted in Table 10 for a constant D/t ratio of 20: PIPE OUTSIDE DIAMETER

WELD TIME

(inches)

(minutes)

8.625

6

10.750

6

12.750

9

14.000

5

16.000

6

20.000

8

24.000

10

Table 10 – Mechanized welding time Note: Time estimated excludes inspection and coating and allows for increasing number of welding heads as diameter permits.

The mechanized welding system is an automatic orbital welding robot designed to produce high quality girth welds using either the dual torch welding head or the single torch welding head combined with the following welding process: -

GMAW: Gas Metal Arc Welding

-

PGMAW: Pulsed Gas Metal Arc Welding

-

GTAW: Gas Tungsten Arc Welding

Some types of welding machine are presented hereafter: y Saturne 8T (from ETPM): This machine consists of 4 arms supporting each a dual torch welding head, travelling around the pipe, guided by a horseshoeshaped ring (see figure 24). With its 8 welding torches, it is capable of high deposit rate in a narrow gap groove and is well adapted to weld thick and large diameter pipes (over 20”). The system is well suitable for pipeline in the range from 20” to 42” in diameter, and 16mm to 33mm in wall thickness.



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The system is fully automatic: -

The welding torches are accurately guided on the center line of the groove,

-

The computerized system drives all operations such as torch positioning, torch start-stop to the selected cycle sequence and other welding parameters which are pre-set for each pass.

Horseshoe shaped ring

Pipe

Wire

Welding head

Figure 24 – SATURNE 8T

The operator has no influence over the welding operations. He only concentrates on positioning the machine, watching the molten pool and selecting the automatic cycle and general safety.



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y SATURNAX (from ETPM): The welding system is composed of a self propelled carriage guided on a pre set ring around the joint and supporting a dual torch welding heads, and a fully integrated module with DC power sources and Electronic Control Units (see figure 25).

Figure 25 – Single welding head SATURNAX The light weight bugs carrying the welding torches can be handled easily by the operator. No need to touch the welding carriage when welding, they are fully automatic except for the welding torch tracking relative to the joint bevel. This can be adjusted by remote control if necessary with a trigger on a small handset. The electronic control units contain welding programs and safety devices. A SATURNAX system with double dual torch welding heads is also available in the industry. •

Single torch welding head using GTAW: The welding system is composed of a self propelled carriage guided on a pre set ring around the joint and supporting a single torch welding head, and a fully integrated module with DC power sources and Electronic Control Units (see figure 26). Wire feeder

Welding torch Welding head

Pipe

Preset ring

Figure 26 – GTAW welding head Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The welding head is computer controlled and is pre-programmed with the welding procedures for root, hot, fill and cap passes. The power supply is also a computer controlled with full control of pulse parameters, including pulse peak currents, pulse "on-time", pulse "off-time", pulse frequency, back ground current and average voltage as a function of wire speed. Note: The welding procedure used for J-Lay is a narrow gap technique depositing an external root against a copper back-up. The copper back-up is integral to the internal line-up clamp. The design of the back-up bar is a circumferential row of 1-inch by 2-inch wide copper segments. Each segment has a spring mounted on each end so that the segment could pivot and adjust to any high low on the pipe inside diameter.

Mechanized welding procedure uses Ar-CO2 gas mixture as a shielding gas.

6.5.3

Electron Beam Welding

This method has already being applied in the aircraft, nuclear and automobile industries and had three main advantages: y Very short welding operations, since welds are made in a single run in the horizontal position, even for heavy thickness; y In these conditions it is possible to weld high yield strength steels without a postweld heat treatment; y It is possible to fully automate the welding operation, thus increasing its reliability. The electron beam welding process consists of two guns moving around the pipes to be welded in a chamber in a primary vacuum (10-2 Torr). The vacuum tightness is ensured on the inside and on the outside by seals placed directly on the pipes (see figure 27).

Seal

Upper pipe

High power electron gun

External chamber

Weld joint

Lower pipe

Figure 27 – Electron beam welding



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The adoption of this technology applying mobile high power electron guns working in a primary vacuum does nevertheless require that a certain number of problems are solved: y Adaptation of the process to the metallurgy of API steels, y Maintaining of a vacuum around the pipe during welding, y High reliability of the generators and operation on a barge in a marine environment. A wide clearance seal made of reinforced elastomer has made possible the creation of a vacuum around the pipe in a matter of seconds and then maintained it at 10-2 Torr throughout the welding operation. An accurate positioning of the beam on the joint is one of the requirements of electron beam welding because the very high power density required to produce the weld is obtained by concentrating a focal spot of 1 mm in diameter onto the joint. Therefore, the tolerances concerning the positioning of the beam on the joint, as well as the maximum permissible clearance between edges are below 1 mm. This creates a problem when the pipe strings are long and large in diameter weighting over 10Te. The machine containing electron guns is protected against the harmful effect of weathering and marine environment by a welding chamber divided into two parts: (1) an external chamber and (2) a pressure lock. A primary vacuum is constantly maintained in the external chamber, thus limiting communication with the marine atmosphere to maintenance operations, which is very limited in number since the guns have long lifetime cathodes. This external chamber in which a vacuum is always maintained houses the guns and nearly all mechanisms of the machine, thus protecting them against the harmful effect of the marine environment. The pressure lock, however, is brought back to atmospheric pressure at every cycle. The electron beam welding technique is capable to weld in 3 minutes a 1.25-inch thick, 24inch pipe.

6.5.4

Flash Butt Welding

This method has been proven successful in welding land pipelines in the Soviet Union. Thousands of kilometers of pipelines with diameters up to 24-inch have been laid, and machines for laying 56-inch are available. It is composed of a lower and upper frame structure. Supporting columns connects the frames. The lower chuck jaws are directly connected to the lower frame. The upper chuck jaws travel on a carriage saddle. A hydraulic press system supported by the upper frame controls the upper chuck jaws. Between the upper and the lower chuck jaws the inductive coils are arranged to swing out (see figure 28).



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Figure 28 – Prototype of the flash butt welding machine The technical data of the machine for welding X 60 pipes of 30" diameter and 40mm wall thickness is as follows: y Dimensions

7.1 m x 4.5 m x 4.7 m

y Max welding cross section

up to 100,000 mm2

y Connection voltage

380V/50 Hz

y Transformer capacity y Welding current

3,380 kVA at 50% operating factor

y Upsetting force

max. 5,000 kN

y Normalizing facility

1,600 kW, 150 – 350 Hz

max. 360 kA

The first phase of the flash butt welding method for pipes involves closing the gap between the two pipes while impressing high current and low voltage. At the points of contact the material is fused by the high current density and vaporises generating high pressure. By this the fused metal is ejected outward and the admission of oxygen to the weld is avoided. After a certain period of flashing the ends of the pipes are forced or upset together. The success of a flash butt welding machine depends substantially on obtaining a uniform heating-up profile (as free of oxides as possible) at the moment of upsetting. This presupposed that sufficient electrical and mechanical powers are provided. The larger the cross sections welded together, the more difficult is establishing that condition. To meet these requirements, first an inductive preheating is connected in series before the flash butt welding. The pipe ends to be welded together are heated up to 950 °C. Then in the flashing process sufficient welding temperature can be achieved in a very short period of time because of preheating. An even current distribution over the entire pipe radius is also established by proportionate arrangement of several electrodes at the pipe within small distances from the transformers. The procedure of the flashing process is computer controlled so that it is reproducible Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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concerning all important data: flashing speed, flashing acceleration, welding voltage, flashing current, etc. After achieving an optimal heat profile the upsetting process is brought into action, as determined by the upsetting force, speed and distance. After the upsetting and the cooling down of the weld there is a coarse-grain structure in the weld because of flashing with high heat input in the weld area. That structure does not nearly have the ductility and deformation resistance quality of the unaffected material. Therefore an inductive normalizing of the weld area is connected after cooling down to temperatures less than 300 centigrades. By this provision a fine grain structure in the weld is achieved, meeting the requirements of offshore pipelining. Having finished the post weld heat treatment, the rough edges inside and outside are sheared off. Inside a special cutting pig system is used, while outside a rotating milling cutter is used. The welding parameters of X52 pipe having dimensions 16-inch OD x 12.7mm wall thickness are as follows: y Welding voltage y Flashing current

8.6 V 17 kA

y Flashing speed

0.4 mm/s

y Flashing distance y Upsetting current

10 mm 50 kA

y Upsetting force

600 kN

y Upsetting speed

70 mm/s

y Upsetting distance y Preheating and postheating temperature

20 mm 950 centigrades



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6.5.5


Radial Friction Welding

Radial friction welding is a variant of conventional friction welding developed as a one-shot joining technique for pipelines. This process is accomplished by butting together two pipes with beveled ends in axial alignment which are held by clamps to prevent the pipes from rotating or moving apart (see figure 29). Stationary clamped pipe

Mandrel

Consumable ring

Pipe with end beveled

Consumable ring

Figure 29 – Radial friction welding principle (under development by SCS) A heat resistant mandrel is expanded inside the pipe bore at the weld location. This mandrel serves to align the abutting pipes and to apply the radial welding pressure. The close fit of the mandrel prevents flash ingress into the bore leaving a smooth internal profile to the weld. A solid ring of the same material as the pipe is machined on the inside diameter to a sharper angle than the angle between the bevelled ends of the abutting pipes. The ring is gripped with the jaws of the radial compression unit and rotation and compression is started so that the ring is progressively forced into the V-shaped preparation. Friction heat sufficient for welding is produced and after a suitable metal displacement, rotation is ceased and the radial pressure maintained to consolidate the weld (see figure 30). Pipe weld after machining

After welding

Figure 30 – Welding sample Radial friction welding is a solid phase joining process and is therefore suitable for a wide range of materials including many which are unsuitable for, or cannot be welded economically by fusion welding. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Radial friction welding machine covers flowlines in the size range from 6" to 12.75" O.D. 7.5mm to 30mm wall thickness, and is able to weld in cycle times of typically 20 seconds or less the following material types: y API 5L X42-X70 y Duplex Stainless Steel y Martensitic stainless steel y Titanium alloys y Internally CRA clad pipe Radial friction welding is suited to flowline laying due to the following main benefits: y It is an automated, machine tool based process which is highly repeatable and does not rely on operator skill y The welding speed is faster than arc fusion welding making single station operation economic. Unlike conventional arc welding which relies heavily on welder skill and post weld nondestructive examination (NDE) for quality control, radial friction welding is an automated process which produces a solid phase weld i.e. without fusion of the pipes or consumable ring. The primary measure in assuring weld quality is therefore the monitoring of machine parameters during the weld cycle to ensure that settings such as speed, force and displacement have been kept within predetermined tolerances. The more traditional quality control checks can then be performed on the finished welds using visual and NDE techniques.

6.5.6

Mechanical Connectors

Two types of mechanical connectors are being promoted for faster pipeline laying operation: •

Threaded and coupled connectors (e.g. Vallourec, Hydril)

•

“Snap and lock” device (e.g. Merlin and Thor connector from Oil States Industries and Wyman-Gordon respectively)

Subsea pipeline construction by lowering free-flooding 72m long string pipes has already been used in the North Sea to form the 24” BP Harding pipelines. A seabed hydraulic crawler connected the strings with «Merlin» snap and lock connectors. However insufficient field proven records might prevent the mechanical connector technology to be adopted for pipe-lay operation.



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6.6 6.6.1


Weld Inspection Introduction

The inspection of butt welds in offshore pipeline production can be performed either by radiographic testing or ultrasonic testing. These two inspection techniques are described in the following sections.

6.6.2

Radiographic Testing

Conventional film radiography refers to the inspection process in which a film media is exposed to X or Gamma radiation, chemically developed to form an image, and then interpreted to help ascertain weld acceptability (see figure 31). Film and screens inside cassette

Internal mechanical crawler provides x- or gamma ray sources

darkroom facility (houses unexposed and developed film, chemicals, high speed film dryer, and high intensity light viewer)

Figure 31 – Conventional film radiography layout The radiation source is provided by an internal crawler when internal shots are made. The basic consideration in the use of radiographic testing is the qualification of the image against a specified standard. Using a given exposure geometry or technique, an image must be qualified before it is interpreted. Qualified images meet sensitivity and density requirements; they are also properly identified for purposes of traceability. Sensitivity of the film is assured with the use of properly placed image quality indicators (IQI's). Placed next to the weld at specified increments, image quality indicators assure the inspector that image contrast sensitivity and resolution are adequate to visibly detect discontinuities in accordance with the governing standard. In the United States, the standard API 1104 or ASME hole penetrameter is the image quality indicator. "2%-2T" sensitivity is a common requirement of the film images. The penetrameters are chosen with regard to pipe wall thickness and weld reinforcement. "2%" refers to the thickness of the penetrameter as related to the thickness of the steel that the radiation must penetrate. When "2T" is specified, it is required that the "2T" hole in the penetrameter appears in the radiographic image. In Europe, wire "DIN" image quality indicators are the standard. The ability to resolve wires of decreasing diameter on a given specimen relates directly to increasing image sensitivity. A lesser known image quality indicator is called the CERL IQI. It is composed of three parts; the first part is a flexible step wedge which is used to measure thickness sensitivity. The second and third part are metal wires which are closely spaced and dimensionally graded in Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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geometric progression. The unsharpness of the image is measured by the least discernable spacing between two wires. The density or relative darkness of an image is a second consideration in qualifying a radiograph. Density is measured on a scale called Hurter-Dreffield (H&D) units. Lighter film obtains lower valued H&D units while darker film obtains higher values. For film radiography, the range of acceptable density falls approximately between 1.8 and 4.0. Most specifications require that identification of weld images appear on the radiograph so that the image can be traced back to the weld. Improper identification can be cause for rejection of the radiograph. Currently, lead numbers and flashing are the primary means for identifying radiographs. The inspection cycle time is the time commencing with the arrival of the pipe at the inspection station and ending with the final interpretation decision on weld quality. In conventional film radiography, the following sequence of events occur during the cycle time: 1.

Pipe stops at inspection station.

2.

Radiation source is positioned at the weld location.

3.

Film is wrapped around the joint.

4.

Film exposure is made.

5.

Film is transported to the dark room.

6.

Film is developed

7.

Film is dried.

8.

Film is interpreted.

The minimum cycle time for conventional radiography on pipeline operations is four minutes to read film wet and four and one-half minutes to read film dry. These numbers represent the physical minimum times using hot chemicals and high speed dryers while not sacrificing image quality. Mechanical and human operations are the main parameters which govern the operating reliability of conventional radiographic systems. Operating personnel control such functions as exposure time, chemical temperatures, placement of film in cassettes, lead shielding, record keeping, and interpretation. Exposure time is currently regulated manually and controlled with a timer. Film development has become almost fully automated and less subject to human variability. Shielding must sometimes be replaced to avoid scratches appearing on the radiographic images. Film is interpreted on a high intensity light viewer screens. For safety reason, the current total time of radiation exposure is calculated and safety areas are delimited so that personnel will not be overexposed. The total time for exposure at a given radiographic station on the laybarge during one day usually will not exceed two hours if 180 joints per day (4 minute cycle time) is assumed. This also assumes a 20 second exposure. Radiation safety zones are determined by marking off an area outside of which exposure will be limited to two milliroentgen per hour (2mR).

Note: The inside pipe diameter is a limitation in Radiographic testing using an internal crawler as radiation source. The minimum inside pipe diameter is 6-inch. For smaller pipe diameter, the radiation source is positioned on the weld joint in the opposite side from the film.



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6.6.3


Ultrasonic Testing

The orbital ultrasonic testing allows full circular weld coverage inspection in a single pass, with real time interpretation. The automated ultrasonic system for weld inspection consists of the following major components (see figure 32): 1.

32-Channel Ultrasonic Flaw Detector

2.

Coupling Monitors

3.

Data Acquisition Module

4.

Temperature Control Module

5.

Graphical User Interface

6.

Data Storage (Optical Disk)

7.

Graphical Output

8.

Ultrasonic Scanning Head

9.

Tandem or Focused Transducers Scanning head

Control station

Weld joint Control monitor

Transducers

Umbilical to control station

Processing system

Preset band

Figure 32 – Automated ultrasonic control system Every pipe size, wall thickness and welding procedure requires a different ultrasonic configuration. Prior to the inspection process, a section of pipe is selected from project material for construction of the calibration standard, so that the standard has similar metallurgical properties and the same method of manufacture as the project pipe. The weld profile is analyzed and segregated into planes based on the geometry of the profile and desired resolution necessary for the acceptance criteria. A machine drawing is then generated providing reflectors in positions simulating the weld profile. For each designated plane, a transducer angle is determined. Focal lengths and beam sizes are then plotted and optimised to the intended target. For each transducer angle, a velocity measurement is required to accurately determine wedge angles necessary to produce the desired refracted angle in the test material. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Each transducer in the transducer array is then applied to the calibration standard to confirm theoretical calculations for stand-off positioning. Optimized distance settings were then recorded and the transducers mounted in the ultrasonic scanner. Prior to welding, a line is scribed on the pipe surface at a preset distance from the end preparation. This provided a reference point for application of the scanner band. Each transducer was then positioned at its operating distance away from the weld centerline on the calibration standard and adjusted to provide a peak signal from its target reflector in the transducer inspection zone. The peak response is then adjusted to 80% of full screen height for each channel. This is the primary reference level. Volumetric zones required additional gain to detect and characterize indications in their respective zones. A calibration scan is performed after each weld. The ultrasonic scanner employs the same drive band used for welding, so that only a minor change is required for correct scanner positioning. Immediately after welding, a cooling apparatus was applied around the weld to reduce surface temperature to below 90°C, to protect against damage to the transducers caused by excessive heat. The scanner is then latched to band and the zero point set to the weld button. The operator initialized the inspection interface and proceeded with the one pass weld scan. Repair welds are examined in a similar fashion. The ultrasonic system provides a proprietary software interface for correlation and display of the inspection data. The software is designed with a number of features which provided assistance to the operator for characterization, sizing and disposition of indications. These features included variable color spectrum ranges for rapid identification of both amplitude and transit distance. A data mapping module is included which combined both indication severity and position in a single display. The Graphical User Interface also included a convenient method for calculating defect lengths and electronic marking of these areas. Weld imperfection indications are evaluated by the ultrasonic operator based on the established acceptance criteria and immediately after scanning and weld disposition, copies of the ultrasonic inspection process are written to magnetic media along with a graphical print of the inspection run. The average cycle time of ultrasonic inspection is 4 minutes for a 14-inch pipeline.

6.6.4

Remarks

Methods of Non Destructive Testing are to be chosen with due regards to the conditions influencing the sensitivity of the methods. The method's ability to detect imperfections is to be considered for the material, joint geometry and welding process used. Since the NDT methods differ in their limitations and/or sensitivities it may be required to combine two or more methods to ensure optimum probability of detection of harmful defects. For detection of internal imperfections either ultrasonic and/or radiographic testing is to be used. Radiographic testing is generally preferred for detection of volume imperfections. Ultrasonic testing is generally preferred for detection of planar imperfections. Whenever determination of the imperfection height is necessary, ultrasonic testing is required.



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7



7.1

Heavy Lift Vessels

Figure 33 – HEEREMA BALDER

TYPE:

PIPELAY CAPABILITY:

SSCV (Semi Submersible Crane Vessel)

Type: J-Lay (2 x 6 Field joints)

DIMENSIONS:

Ramp angle: 30° - 95°

Length: 154m

Range of pipeline: 3" – 30"

Breath: 86m

Water depth: 3000m

Depth (Main deck): 42m

Lay tension: 500T

Draft: 11 – 27m

Max. pipe load: 7000T

DISPLACEMENT:

Average lay speed: 1000 – 3000 m/day

Displacement at operating draft: 100,000T

DECK AREA/LOADING:

CRANE / LIFT CAPACITIES:

Deck space: 6,200T

2 Main cranes: 2,700T/3,600T

Deck load: 8,000T

POSITIONING SYSTEM:

ACCOMMODATION:

Dynamic positioning: Class 3

402 persons SPEED: Transit speed: 6 knots



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OTHER SSCVs:

Figure 34 – SAIPEM 7000

Figure 35 – HEEREMA THIALF

Figure 36 – HEEREMA HERMOD

Figure 37 – J.Ray McDermott DB 101



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7.2


Pipe Lay Vessels

7.2.1

J-Ramp Lay Vessels

Figure 38 – SAIBOS FDS (Field Development Ship)

TYPE:

PIPELAY CAPABILITY:

J –Ramp Pipe Lay Vessel

Type: J-Lay (4 Field joints)

DIMENSIONS:


Length: 157.5m


Breath: 30m

Water depth: 2000m – 2500m

Depth (Main deck): 12.4m

Lay tension: 400T

Operating draft: 7m


DISPLACEMENT:

Average lay speed: 1000 – 3000 m/day

Displacement at operating draft: 25265T

FLEXIBLE LAY CAPABILITY:

POSITIONING SYSTEM:

Flexible storage: 4100T

DP: Class 3 (AUTRO)

Lay tension: 270T


UMBILICAL LAY CAPABILITY:

1 Main cranes: 600T

Umbilical storage: 3000T

2 Aux. Cranes: 30T each

Lay tension: 140T

SPEED:

ACCOMMODATION:

Transit speed: 14 knots

200 persons



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OTHER J-Ramp Lay Vessels:

Figure 39 – J.Ray McDermott DB 50

Figure 40 – SCS SEAWAY FALCON



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7.2.2


Vertical Reel Lay Vessels

Figure 41 – CSO Deepwater Pipelay Vessel

TYPE:

PIPELAY CAPABILITY:

Vertical Reel Lay Vessel

Type: two 34m vertical reels

DIMENSIONS:


Length: 195m


Breath: 30m

Water depth: 2500m

Depth (Main deck): 13.5m

Lay tension: 550T

Operating draft: 7.5m

Max. pipe load: 5000T (2500 T on each reel)

DISPLACEMENT:

Average lay speed: 12000 m/day



POSITIONING SYSTEM:


DP: Class 2

Lay tension: 550T

SPEED:




ACCOMMODATION:

Lay tension: 60T - 120T

200 persons (estimated)



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OTHER Vertical Reel Lay Vessels:

Figure 42 – DSND FENNICA

Figure 43 – ETPM NORLIFT

Figure 44 – CSO APACHE



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7.2.3


Horizontal Reel Lay Barges

Figure 45 – GLOBAL INDUSTRIES HERCULES

TYPE:

PIPELAY CAPABILITY:

Horizontal Reel Lay Barge

Type: 34m horizontal reel

DIMENSIONS:

100m radius Steep S stinger

Length: 135m


Breath: 43m

Water depth: 2440m


Lay tension: 555T

Operating draft: 5m


POSITIONING SYSTEM:


DP: Class 2




Main crane: 2000T

Lay tension: 555T

DECK SPACE/LOADING:


Deck area: 2137m²


SPEED:

Lay tension: 120T


ACCOMMODATION: 191 persons



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OTHER Horizontal Reel Lay Barge:

Figure 46 – GLOBAL INDUSTRIES CHICASAW



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7.2.4


Steep S Pipe Lay Vessels

Figure 47 – ALLSEAS SOLITAIRE

TYPE:

PIPELAY CAPABILITY:

Steep S Pipe Lay Vessel

Type: Firing line

DIMENSIONS:

110m radius Steep S stinger

Length: 298.5m

Range of pipeline: 6" – 18" (up to 60”)

Breath: 40.6m

Water depth: 3000m


Lay tension: 400T

Operating draft: 8.5m


DISPLACEMENT:


Displacement at operating draft:

SPEED:

POSITIONING SYSTEM:


DP: Class 3 (AUTRO)

ACCOMMODATION:


420 persons

2 Cranes: 25T each



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OTHER Steep S Pipe Lay Vessel:

Figure 48 – ALLSEAS LORELAY



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7.3


Flexible Lay Vessels

Figure 49 – CSO SUNRISE 2000 TYPE:


Flexible Lay Vessel

Type: Vertical Laying System (VLS)

DIMENSIONS:

Range of flexible: 4" – 16"

Length: 136m

Water depth: 2500m

Breath: 30m

Lay tension: 270T


Max. flexible load: 3800T

Operating draft: 6m

Average lay speed: 15-30m/mn

DISPLACEMENT:




POSITIONING SYSTEM:

Lay tension: 38T

DP: Class 2

SPEED:



2 Main Cranes: 75T each

ACCOMMODATION:

1 Aux. Crane: 30T

72 persons

DECK AREA/LOADING: Deck area: 3000m² Deck loading: 5000T



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OTHER Flexible Lay Vessels:

Figure 50 – CSO FLEXINSTALLER

Figure 51 – CSO FLEXSERVICE 1



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7.4


Umbilical Lay Vessels

Figure 52 – SCS SEAWAY CONDOR

TYPE:


Umbilical Lay Vessel

Type: Horizontal reel + 12m radius chute

DIMENSIONS:

Range of flexible: 4" – 6"

Length: 101m

Water depth: 1650m

Breath: 23m

Lay tension: 40T


Max. flexible load: 400-1250T

Operating draft: 6m

Average lay speed: 15-30m/mn

POSITIONING SYSTEM:


DP: Class 2



Lay tension: 40T

Crane: 65T

SPEED:

DECK AREA/LOADING:


Deck area: 1110m²

ACCOMMODATION:

Deck loading: 1860T

100 persons



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OTHER Umbilical Lay Vessel:

Figure 53 – SCS SEAWAY EAGLE



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DEEPWATER INSTALLATION VESSELS SUMMARY TABLE



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SSCV

Balder

Hermod

Thialf

SaiBos 7000

DB 101

Operating

GOM

Far East

North Sea

North Sea

GOM

areas

North Sea

GOM

Heerema

Heerema

Heerema

Saipem

JRMcD

1978-1998

1 978

1 985

1987-1999

1 978

LOA (m)

154

154

201,6

198

146,3

Breadth (m)

86

86

88,4

87

51,9

Operators Built (converted)

Operating Draft (m)

25

25

26,6

27,5

23,5

Depth maindeck (m)

42

42

49,5

43,5

36,5

Displacement (t)

100 000

110 000

180 000

172 000

90 000

GRT (t)

48 511

73 887

136 709

117 812

32 509

Deckload (t)

8 000

8 000

12 000

15 000

4 000

Payload (t)

7 000

-

-

10 000

2 400

Deckspace (m²)

6 200

DP Class

6200 (20t/m²) 9290 (15t/m²)

4 000

3

anchored

3

3

anchored

27 000

19 355

27 600

44 800

9 900

Bollard pull (t)

450

140

215

370

0

Headsea (knt)

50

-

40

65

-

Beamsea (knt)

50

-

40

60

-

Bunkers (m3)

5 838

5 850

8 220

7 770

3 248

Consumption (t/d)

40-60

?

50

60

?

Power (KW)

Speed (knot)

6

6

6

9

12

Pipelay type

J-Lay (2x6FJ)

no

no

J-Lay (2x4FJ)

no

Ramp angle (°)

30°-95°

-

-

30°-85°

-

Water depth (m)

3 000

-

-

2 000

-

Tension (t)

500

-

-

525

-

7 000

-

-

7 000

-

33

-

-

33

-

27

-

-

27

-

-

-

15

-

-

-

-

1000-3000

-

WOROV

?

Saturation diving

Max pipeload (t) Length (km) vs ID 16" ID 18" ID 20" ID 24"

15

-

-

1000-2000

-

?

?

?

?

?

?

?

14p

?

Accommodation

402

336

736

800

279

Twin Cranes (t)

ID 30" Average lay speed (m/d)

-

2700/3600

3600/4500

6000/6000

7000/7000

3 175

Boom (m)

110

110

110

150

100

Lift (t) at

500 t

no

no

no

no

water depth (m)

3000 m

-

-

-

-

Lift (t) at

1500 t

no

no

no

no

water depth (m)

1500 m

-

-

-

-

Table 1 – Semi-Submersible Crane Vessel Summary Table



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DEEPWATER INSTALLATION CONTRACTORS



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ALLSEAS MARINE CONTRACTORS SA

COFLEXIF STENA OFFSHORE GROUP

5 route de la Coula

23 avenue de Neuilly

1618 Chatel – St Denis

75116 Paris

Switzerland

France

Tel: (21) 948 91 91

Tel: (1) 40 67 60 00

Fax: (21) 948 91 41

Fax: (1) 40 67 60 03

DSND Sondenfjeldske AS

ETPM

Radhusgt. 23 P.O. Box 752 Sentrum

32 avenue Pablo Picasso TSA 76001

N-0106 Oslo

92754 Nanterre cedex

Tel: (47) 22 41 21 50

Tel: (1) 40 97 63 00

Fax: (47) 22 41 06 50

Fax: (1) 40 97 63 33

GLOBAL INDUSTRIES, Ltd

HEEREMA MARINE CONTRACTORS

900 Halliburton center 5151 San Felipe

16th Floor Portland House

Houston, Texas 77056

Victoria

Tel: 713 624 2222

London SW1E 5HH

Stag Place

Tel: (0171) 932 1700 Fax: (0171) 932 1750 J RAY MCDERMOTT SA

ROCKWATER Ltd

Albemarle House

Stoneywood Park

1 Albemarle Street

Dyce

London W1X 3HF

Aberdeen AB21 7DZ

Tel: (0171) 629 4411

Tel: (01224) 722877

Fax: (0171) 629 0145

Fax: (01224) 795746

SAIPEM

SAIBOS (Services) SAS

Via Martiri di Cefalonia, 67

3 rue Stephenson

20097 S.Donato Milanese

Montigny-le-Bretonneux

Italia

78884 Saint-Quentin-Yvelines Cedex

Tel: 39 2 520 34075 Fax: 39 2 520 44289

France Tel: (1) 30 60 66 60 Fax: (1) 30 60 66 00

STOLT COMEX SEAWAY GROUP

STOLT COMEX SEAWAY S.A.

Bucksburn House

BP 69

Howes Road

467 Chemin du Littoral

Bucksburn

13321 Marseille Cedex 16

Aberdeen AB21 9RQ

France

Tel: (01224) 718200

Tel: (33) 4 91 09 68 01

Fax: (01224) 715129

Fax: (33) 4 91 09 68 00



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Ships, Barges

FDS

Solitaire

Lorelay

Falcon

Apache

CSO DPV

DB 50

DB 16

Norlift

Chicasaw

Hercules

Fennica

Operating

W.Africa

North Sea

North Sea

North Sea

North Sea

North Sea

GOM

GOM

North Sea

GOM

GOM

North Sea

areas

S.Atlantic

S. Atlantic

S.Atlantic

S.Atlantic

S.Atlantic

S.Atlantic

Brazil

Operators

SaiBos

Allseas

Allseas

SCS

CSO

CSO

JRMcD

JRMcD

ETPM

Global

Global

DSND

Built (converted)

2 000

1972-1998

1 986

1 995

1979-1993

2 000

1986-1991

1 996

1992-1995

1 970

1975-1998

1992-1997

LOA (m)

157,5

298,5

182

149

123

195

152

122

98

84

122

116

30

40,6

26

21

23,34

30

46

30

25

24

43

26

Operating Draft (m)

7

8,5

7

8

5,6

7,5

6

5

6

2,9-3,7

5

8

Depth maindeck (m)

12,4

24

16

13

8,69

13,5

13

9

7

6

8

13

?

30 000

?

?

?

?

?

?

?

10 385

7 280

?

29 722

7 684

5 497

?

?

8 600

Breadth (m)

Displacement (t)

25 265

?

GRT (t)

?

?

DWT (t)

10 500

125 000

Deckload (t)

4 000

Payload (t) Deckspace (m²) DP Class

?

?

?

?

?

?

4 604

?

?

4 870

4000+

2 000

2 000

7 000

10000+

?

3 000

3 000

?

3 000

5 600

14 600

4 000

5 000

2 500

7 000

10000+

?

3 000

3 000

?

3 000

3000 (10t/m²)

?

2 120

2 400

235 (5t/m²)

800

2935-10t/m²

?

1 200

1 800

2 137

1050-10t/m²

3 (AUTRO)

3

3 (AUTRO)

2

2 (AUTR)

2

2

2

2

2

2

3 (AUTRO)

Power (KW)

25 000

48 000

18 240

13 200

9 720

20 000

13 550

8 000

10 000

2 500

20 000

21 000

Bollard pull (t)

100

450

100 ?

85

70

100?

80

?

80

35

70

200

Headsea (knt)

60

60

?

60

50

60

?

?

50

?

?

60

Beamsea (knt)

35

45

?

30-35

20-25

30

?

?

20-25

?

?

20-25

Bunkers (m3)

2 500

?

3 000

2 800

900

?

1 800

?

1 320

227

2 574

1 580

Consumption (t/d)

20-32

?

30

20-32

?

30

?

?

16-30

?

?

15-30

Speed (knot)

14

14

13

13

11

14

9

6

10

5

11

13

Pipelay type

J-Lay (4FJ)

S-Lay

S-lay

J-lay

25m VReel

2x34m VReel

J-Lay (4FJ)

18m VReel

18m Reel

24m HReel

34m HReel

Ver.reel

12°-96°

110m radius

60 m radius

21°-90°

18°-70°

16°-90°

30°-87°

30°-87°

30°-87°

30m radius

100m radius

30°-90°

2000-2500

3 000

1 650

1 000

1 800

2 500

2 000

1 000

1 000

900-1800

2 440

2000 ?

Stinger, Ramp angle (°) Water depth (m) Pipe Tension (t)

400

400

135

75

160

550

170

125

125

67

555

120

Max pipeload (t)

4000+

14 000

4000 +

3 000

2 000

5 000

1 250

1 250

1 250

2 268

7 000

1 100

Length (km) vs ID 6"

107

375

107

80

65

140

42

42

42

31

190

40

ID 8"

62

217

62

45

30

80

22

22

22

18

110

20

ID 10"

40

140

40

30

24

60

15

15

15

14

70

15

ID 12"

30

105

30

20

16

45

11

11

11

6

50

10

ID 14"

25

88

25

no

12

37

?

no

no

no

50

no

ID 16"

20

70

20

no

8

25

?

no

no

no

40

no

ID 18" Average lay speed (m/d)

15

53

15

no

no

18

?

no

no

no

30

no

1 500

4 000

2 500

1 500

12 000

12 000

1 500

10 000

12 000

12 000

12 000

12 000

Piggy Back

6"(300t)

no

no

6" (400t)

8" (320t)

4"(320t)

no

no

no

6" (160t)

8" (320t)

6" (160t)

Flexlay type

tensioner

no

no

tensioner

reel+tens.

reel+tens

reel+tens.

reel+tens

reel+tens.

Hor.reel

reel+tens

reel+tens.

Storage (t)

4 100

3 000

2 470

7 000

1 250

1 250

1 250

2 268

7 000

1 100

Tension (t)

270

135

197

550

170

125

120

67

555

120

tensioner

reel+tens.

reel+tens

reel+tens.

reel+tens

reel+tens.

Hor.reel

reel+tens

reel+tens.

3 000

2 470

7 000

1 250

1 250

1 250

2 268

3 000

1 600

Umbilical lay Storage(t) Tension (t) WOROV OBSROV

reel+tens.

no

no

4 100 80 2x150 hp

?

2x100hp

30

30-120

60-120

30-120

30-100

30-80

67

120

30-80

2x50hp

2 x 100hp

2 x 100hp

2x100hp

2x100hp

?

2x75hp

2x150hp

2x100hp

no

?

achille

no

no

?

?

?

no

?

?

option

no

?

no

no

no

-

-

16p

no

9p

no

200

420

216

105

100

?

237

147

80

65

191

82

Crane (t)

600t-30m

no

300t-14m

30t-10m

27t-10m

30t-20m

4000t

600t-23m

300t-12m

116t-16m

2000t

15t-14,5m

Boom (m)

100

no

37m

30

24m

?

105m

85m

50m

40m

70m

20m

Aux.Crane

2x30t-38m

2x25t-33m

no

2x30t-10m

no

?

?

no

no

90t-20m

no

no

no

no

no

4x10t

no

no

no

no

no

no

A-frame120t

100t-2000m

no

no

30t hc

no

no

no

no

no

no

no

no

Saturation diving Accommodation (p)

Pipe davit (t) MHS (t) Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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Table 3 - FLEXIBLE AND UMBILICAL LAY VESSEL SUMMARY TABLE Ship

Condor

Eagle

Installer

Flexservice 1

Sunrise

Wellservice

GSV

Lochanar

K3000

Operating

North Sea

Asia

North Sea

Brazil

Brazil

North Sea

North Sea

Brazil

Brazil

areas

S.Atlantic

Pacific

W.A. ?

Operators

SCS

SCS

CSO

CSO

CSO

CSO

Rockwater

DSND

DSND

Built (converted)

1 994

1994-1997

1983-1989

1976-1990

1984-1995

1987-1995

1 998

1992-1998

1992-1999

LOA (m)

101

138

102

129,69

136

111

114

120

120

Breadth (m)

23

19,5

20

17,37

30

23

22

20

20

Operating Draft (m)

6

8

5

7

6

7

7

5

5

Depth maindeck (m)

11

11

7

10,21

10

11

10

7

7

?

?

Displacement (t)

18 885

GRT (t)

6 046

?

4 603

8 060

10 648

9 158

?

?

?

DWT (t)

?

8 250

?

?

?

4 626

6 850

?

?

Deckload (t)

1 860

2 000

2 500

3 000

5 000

1 140

4 500

3 500

3 500

Payload (t)

2 000

3000-6000

3 000

2 600

5 000

-

3 400

3 000

3 000

Deckspace (m²)

1 110

1 300

1000-10t/m²

?

3000-15t/m²

970

1590-5t/m²

?

?

2

2

2

2

2

3

3 (AUTRO)

3

3

7 740

10 700

10 000

7 000

14 000

13 440

10 720

10 000

10 000

Bollard pull (t)

60

120

80

30

65

100

70

80

80

Headsea (knt)

50

50

40

?

50

70

60

?

?

Beamsea (knt)

20-25

30

20-25

?

20-25

35

35

?

?

Bunkers (m3)

1 320

1 610

963

895

2 179

2 388

1 400

?

?

Consumption (t/d)

10-25

10-25

10-25

15-25

16-30

19-30

10-25

15-25

15-25

11

13

12

11

12

12

14

14

14

Hor.reel

tensioner

VLS

tensioner

VLS

VLS

FLS

tensioner

tensioner

12m radius

6m radius

verttical

6m radius

6m radius

vertical

vertical

6m radius

6m radius

1 650

1 000

350

1 000

2 500

450

1 500

1 000

1 000

DP Class Power (KW)

Speed (knot) Flexible lay Overboarding Water depth (m) Tension (t) Max storage (t) Length (km) vs ID 4" ID 6"

Umbilical lay

12

75

125-250

100

270

125

140

100

100

400-1250

3 000

4 000

2 600

3 800

1 200

3 400

3 000

3 000

22

55

84

50

80

24

75

55

55

15

30

42

30

38

12

34

30

30

ID 8"

-

22

26

20

24

8

20

22

22

ID 10"

-

16

18

15

16

6

15

16

16

ID 12"

-

13

16

10

15

5

14

13

13

ID 14"

-

10

14

-

10

4

10

10

10

ID 16"

-

6

6

-

6

2

6

6

6

reel

tensioner

tensioner

tensioner

tensioner

tensioner

tensioner

tensioner

tensioner

Storage(t)

1 250

3 000

3 000

2 600

3 800

1 200

3 400

3 000

3 000

Tension (t)

40

30

30

25

38

30

30

25

25

WOROV

2x100hp

2x100hp

2x75hp

1x75hp

2x150hp

2x100hp

2x100hp

2x100hp

2x100hp

OBSROV

sprint

achille

yes

achille

no

no

no

no

no

Saturation diving

6p

6p

no

6p

no

18p

no

no

no

Accommodation

100

98

60

85

72

149

102

90

90

Crane (t)

65t-15m

100t-10m

25t-19m

20t-13m

75t-15m

2x65t-26m

100t-13m

?

?

Boom (m)

24m

25m

20m

20m

30m

30m

30m

5t-15m

30t-15m

no

no

no

no

15t-15m

no

A-frame 150t

50t hc

no

no

no

no

no

no

Aux.Crane Pipe davit (t) MHS (t) Rev. 0 30/09/2000 DGEP/SCR/ED/TA


30t-15m

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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK TIE-IN METHODS


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TABLE OF CONTENTS 1

INTRODUCTION ........................................................................................................... 4 1.1 SCOPE...................................................................................................................... 4 1.2 REGULATION, CODES, STANDARDS & SPECIFICATIONS ................................................. 5 1.3 DEFINITIONS & ABBREVIATIONS .................................................................................. 6 1.4 REFERENCES ............................................................................................................ 6

2

INTERFACE REQUIREMENT....................................................................................... 7 2.1 GENERAL .................................................................................................................. 7 2.2 SUBSEA PRODUCTION SYSTEM ................................................................................... 8 2.3 FLOWLINE OR UMBILICAL TERMINATION ....................................................................... 9 2.4 OPERATIONAL PROCEDURES ...................................................................................... 9 2.5 SUBSEA FIELD DEVELOPMENT PLAN .......................................................................... 10 2.6 VESSEL .................................................................................................................. 10 2.7 CONNECTION TOOL ................................................................................................. 10 2.8 ROV ...................................................................................................................... 11

3

CONNECTOR TECHNOLOGY AND MANUFACTURER REVIEW ............................. 12 3.1 GENERAL ................................................................................................................ 12 3.2 COLLET CONNECTOR ............................................................................................... 13 3.3 CLAMP CONNECTOR ................................................................................................ 14 3.4 PETROBRAS TRIPLE LINE CONNECTOR ...................................................................... 17 3.5 MERLIN CONNECTOR ............................................................................................... 19 3.6 ELECTRICAL CONNECTOR......................................................................................... 20

4

TIE-IN TOOL TECHNOLOGY REVIEW ...................................................................... 21 4.1 GENERAL ................................................................................................................ 21 4.2 REMOTELY OPERATED TOOLS .................................................................................. 22 4.3 ROV-MOUNTED PULL-IN AND CONNECTION SYSTEMS ................................................. 26 4.4 ROV-MOUNTED CONNECTION SYSTEMS .................................................................... 33 4.5 4.5 "MATIS" API FLANGE TIE-IN TOOL...................................................................... 35

5

TIE-IN METHODS ....................................................................................................... 36 5.1 GENERAL ................................................................................................................ 36 5.2 LAY-DOWN & PULL-IN .............................................................................................. 37 5.2.1 Description .................................................................................................................37 5.2.2 Tie-in procedure.........................................................................................................38 5.2.3 Utilisation and limitations ...........................................................................................39 5.3 DIRECT PULL-IN ....................................................................................................... 40 5.3.1 Description .................................................................................................................40 5.3.2 Tie-in procedure.........................................................................................................41 5.3.3 Utilisation and limitations ...........................................................................................41 5.4 DEFLECT-TO-CONNECT ............................................................................................ 42 5.4.1 Description .................................................................................................................42 5.4.2 Tie-in procedure.........................................................................................................43 5.4.3 Utilisation and limitations ...........................................................................................43 5.5 VERTICAL STAB, HINGE-OVER & LAY-AWAY ............................................................... 44 5.5.1 Description .................................................................................................................44 5.5.2 Tie-in procedure.........................................................................................................45 5.5.3 Utilisation and limitations ...........................................................................................45 5.6 SURFACE TIE-IN, LAY-AWAY & LAY-TO....................................................................... 46 5.6.1 Description .................................................................................................................46 5.6.2 Tie-in procedure.........................................................................................................47 5.6.3 Utilisation and limitations ...........................................................................................48


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5.7 VERTICAL CONNECTION AND TRIPLE FLOWLINE LAY-AWAY .......................................... 49 5.7.1 Description .................................................................................................................49 5.7.2 Tie-in procedure.........................................................................................................50 5.7.3 Utilisation and limitations ...........................................................................................51 5.8 FLEXIBLE JUMPERS .................................................................................................. 52 5.8.1 Description .................................................................................................................52 5.8.2 Tie-in procedure.........................................................................................................52 5.8.3 Utilisation and limitations ...........................................................................................53 5.9 STEEL JUMPERS ...................................................................................................... 54 5.9.1 Description .................................................................................................................54 5.9.2 5.9.2 Tie-in procedure................................................................................................54 5.9.3 Utilisation and limitations ...........................................................................................56 5.10 "RIGI-FLEX" JUMPER................................................................................................ 56 5.11 HYBRID STEEL PIPE & FLEXTAIL ................................................................................ 57 5.11.1 Description .................................................................................................................57 5.11.2 Tie-in procedure.........................................................................................................58 5.11.3 Utilisation and limitations ...........................................................................................58 6

ADVANTAGES & DISADVANTAGES ......................................................................... 59

7

SUBSEA METROLOGY.............................................................................................. 61 7.1 GENERAL ................................................................................................................ 61 7.2 ACOUSTIC BASE LINE ............................................................................................... 61 7.3 TAUT WIRE METROLOGY........................................................................................... 62

8

TIME ESTIMATED FOR DEEPWATER TIE-IN OPERATION ..................................... 63

ANNEX 1: MANUFACTURERS AND CONTRACTORS LIST ............................................ 64


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1


INTRODUCTION

1.1

Scope

As the impact of a tie-in operation on the overall installation cost of a project growths with the water depth, a better understanding of available connection techniques, a judicious choice and an early integration of the tie-in method in the engineering studies are keys to successfully control the whole cost of a deepwater installation project. Performing tie-in in deepwater involves to use diverless and guidelineless methods, with adapted subsea connectors and remotely operated tools. With these aims in view, this document reviews the currently available tie-in methods for deepwater applications. It deals firstly with the interface requirements for a tie-in operation; knowing that tie-in methods and connector hardware are closely related. The main connector systems are then described, prior to reviewing deepwater tie-in methods and their installation performance. The interface requirements between the different subsea structures/equipment and installation means are described in hereafter chapter 2. Such interface engineering must addressed: • • • • • • • •

Subsea Production System design Flowline end termination (typically of 12" NPS) Umbilical end termination (up to 6" OD) Operational conditions Subsea field development plan and sequences Installation vessels Connection tools and finally the ROV capabilities

In the following chapter 3, the existing connector technologies are reviewed and the main manufacturers are listed. With the connector, special tie-in tools are required, either ROV mounted tools or dedicated tools which are remotely operated from the surface tie-in vessel. These tie-in tool technologies are further investigated in chapter 4.


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The key topics of tie-in methods are thereafter detailed in chapter 5 in terms of operational procedures with its application limits and based on the selection of following deepwater applicable techniques: • • • • • • • • • •

Laydown and pull-in Direct pull-in Deflect-to-connect Vertical stab, hinge-over and lay-away Surface tie-in, lay-away and lay-to Vertical connection and triple flowline lay-away flexible jumpers steel jumpers "Rigi-flex" jumpers Hybrid steel pipe and flextail

In chapter 6, the main advantages and disadvantages for each above tie-in methods are presented in a tabular form. The subsea metrology is also an important feature, especially in the case of the rigid steel jumpers. This subject is further detailed in chapter 7. Finally, in chapter 8, times estimated for deepwater tie-in operation are discussed. 1.2

Regulation, codes, standards & specifications

DNV 81: "Rules for submarine pipeline systems". DNV 96: "Rules for submarine pipeline systems" (Limit State Design) ISO/TC67/SC4: • Part 8: Design and operation of ROV interfaces on subsea production equipment • Part 9: ROT intervention systems API 5L & 54C: "Specification for line pipe" API RP 1111: "Recommended practice for design, construction, operation and maintenance of offshore hydrocarbon pipelines" API RP 14E: "Design and installation of offshore production platform piping systems"


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1.3



Connector: Deepwater: DP: FMECA: ID: LARS: NPS: OD: PLEM: ROV: ROT: SPS: Tie-in: 1.4

Connection hardware (clamp, locking mechanism, etc.) deeper than 1000 msw Dynamic Positioning vessel Failure Mode Effect and Criticality Analysis Internal Diameter Launching and Recovery System (for ROVs, ROTs) Nominal Pipe Size Outside Diameter Pipeline End Manifold Remotely Operated Vehicle Remotely Operated Tool Subsea Production System (i.e. subsea structures such as X-mas trees, manifolds, etc.) Methodology, operation procedure for the subsea connection activity

References

This study is based on the following sources • • • •

Industry available documentation such as OTC papers Vendors / Manufacturer published technical data. In house technical data from the subsea contractors. In house past experience in subsea tie-in works

Reference is made to the documents "Umbilicals" and "Sealines", part of the deepwater field development reference book.


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2



2.1

General

The following chart depicts the main interfaces of a tie-in operation, which are then further explained in the following subparagraphs. This clearly shows the importance of an early integration of the tie-in method and connector type in a development project as they interfere with several items such as the subsea structure or installation vessel choice.

Subsea Field Development Plan Subsea Production System

Subsea Flowlines

TIE-IN METHOD

CONNECTOR

Tie-in Tool(s) ROV(s) Tie-in Vessel(s)

Scheme 2.1 - The main interfaces


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2.2



A subsea structure has to be designed and equipped with due consideration of the following additional mechanical aspects: • space/dimension provision for the selected connector, the tie-in tools and ROV operations. • tie-in aid equipment such as guiding devices, latching systems, etc. • equipped with an inboard hub adapted to the future flowline connector • connection/reaction loads which vary with the tie-in method • resist to the in-service load conditions such as temperature, slugging, etc. GUIDE / REACTION POSTS

INBOARD HUB

CONNECTOR

Figure 2.2 - Visund field subsea tree to be connected by the RTS (ROV Tie-in System), by courtesy of Kvaerner


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2.3


Flowline or umbilical termination

The line termination must be designed and equipped with the following considerations: • equipped with the adequate outboard hub adapted to the future connector. • the connection method. Eventual pulling devices, guiding structures, tool jig, etc., may be included in the line head or PLEM design and manufacturing.

Figure 2.3 - Universal Tie-In System (UTIS) termination heads, by courtesy of Kongsberg Offshore 2.4

Operational procedures

The operational procedures will depend obviously on the selected tie-in method and must also consider the following aspects: • surface environmental conditions (weather downtime, launching system, etc.) • water depth (hydrostatic pressure, deployment time, diverless and guidelineless operation) • seabed environmental conditions (soil stability, current, visibility) • remote operation type (ROT, ROV based) • subsea lifting and pull-in requirement • tie-in support vessel deck space and handling facilities • risk analysis based on HAZOP studies and FMECA


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2.5


Subsea field development plan

The subsea field development plan has a great influence on the tie-in method performance as it determines: • the total number of connections, for the initial and future field development phases • the chronological integration of tie-in operations in the whole project • the interference or not with other surface units (drilling rig, production floater, etc.) and other subsea structures during the connection. This has an impact on the tie-in method choice as it determines the available means (tie-in support vessels, tools, vessel coordination, etc.) and sometimes involves some critical phases in the operational methodology such as abandonment of lines prior to their recovery after the arrival of the production floater. 2.6

Vessel

One or several ships of the following types can be involved in a tie-in operation: • Laying vessel • Drilling/completion rig • ROV-support vessel The vessel and tie-in method choices are intimately related. Some tie-in methods require the presence of two vessels (e.g. the Lay-away tie-in method, see "5.6. Surface tie-in, lay-away and lay-to", which requires the simultaneous presence of the laying ship and the drilling rig), this interface can have a costly repercussion on the project. Launching and recovery of both the ROVs and the ROTs can also be defined as an interface item as its performance have a direct impact on the time (hence the cost) of a tie-in operation. 2.7

Connection Tool

The connection tool choice is based on: • the type of connector • the tie-in method • the ROV operation (ROV intensive or ROV used for back-up function only) In the early 80's, tie-in methods were based on two remotely operated tools (ROT), one pullin tool and one connection tool which were run separately. These tools were later in the 80's combined in one Pull-In & Connection Tool (PICT) with cable storage drum installed on tie-in vessel. Recently the industry has introduced the ROV based pull-in and connection tool, which is mounted below the ROV. The connection tool design depends on the connector type (which determinates the required functions: hydraulic supply, torque tool, integrated seal plate handling and replacement tool, etc.) and varies with each SPS manufacturers.


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2.8


ROV

For the ROT/tie-in method, the ROV is used primarily as a visual control during the ROT landing and recovery, and to connect the pull-in wire (see "5.2 Lay-down and pull-in"). Its secondary function is to override some of the ROT main functions in case of an ROT mechanical failure. In this case the main interfaces are related to: • Space/dimension for ROV manoeuvring, docking • Hydraulic aspects of hot stab operations (override functions) • Mechanical interface aspects of ROV manipulator and override valve panels With regard to the ROV mounted pull-in and connection tool, the interface requirements are much more stringent and could referred to "Interface Engineering" encompassing the full scheme, such as: • • • •

Pull-in and connection tool Subsea structures Flowline termination ends ROV Launching and Recovery System

Figure 2.4 - DMAC / ROV based Pull-in and connection, by courtesy of Subsea Offshore Ltd.


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3


CONNECTOR TECHNOLOGY AND MANUFACTURER REVIEW

3.1

General

Deepwater tie-ins imply the use of diverless subsea connectors. Their implementation requires precise alignment (and orientation in the case of multibore connection) that is generally performed in two stages: (1) rough alignment during the hub's approach by the pullin tool or by means of guiding funnel placed on the subsea structure and (2) precise alignment, when the two hubs mate, by the connection tool. This chapter aims to describe the connector technologies available to perform a tie-in operation and to identify the main manufacturers. Two main fluid connection systems are currently available on the market: • Collet connector • Clamp connector These systems allow both monobore and multibore connections as only hubs and seal plates (fitted with guiding pins to perform precise orientation in the case of multibore connector) have to be adapted; thus they can be used to connect flowlines or umbilicals (chemicals, hydraulic supply). The running tool can be either an ROV-mounted tool or a Remotely Operated Tool (ROT) with ROV override functions. An insulation coating can be added at the latest stage on the connection point if required, using for example a doghouse (i.e. an insulated box with an open bottom and horseshoe cutout front and back to allow its landing on the connection prior to its closing). The above mechanical connectors are widely used in deepwater field development, with a large application of collet connectors in the Gulf of Mexico. Other mechanical connectors are available, however with low utilisation (to nil) in deepwater application: • Merlin connector • API flange with "MATIS" ROT Concerning the low and high power subsea electrical connectors, the prevailing concept since the 1980's is the fluid filled connector concept which removes seawater from contact with the critical components. The electrical connectors can be plugged by ROV and are currently available rated up to 11kV at 400A (Tronic connector). The electrical connector cannot accept any mechanical load either during installation or inservice conditions.


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3.2


Collet connector

LOCKING SPRING

ACTUATOR RING COLLETS

COLLET STAB HUB

METAL SEAL METAL SEAL TEST PORT

RECEIVER HUB

Figure 3.1 - Collet connector scheme A collet connector basically consists of two mating hubs: a stab (inboard) hub and a receiver (outboard) hub which supports the collets, the actuator ring, the locking springs and the hydraulic cylinders. The metal seal may be retained in either the stab or the receiver hub, maintained in position by mechanical adjustement. The functions of each component and operations of the collet connector may be described as follows: • The first step of a connection operation is the stabbing: the two hubs are brought into approximate contact (by a stroking tool). Few degrees misalignment, depending on the diameter of the line, can be corrected by the collets (e.g. +/-2° angular misalignment and +/-35mm axial offset satisfy most applications). • Locking is then performed by the collets. This is done by applying hydraulic pressure to the cylinders, which transmit a force in the axial direction to the actuator ring; the actuator ring then moves axially and forces the collets radially inward. • The collet connector is maintained closed by the locking springs; this preload keeps the two hubs and the metal seal in tight contact and determines the bending strength of the connector. The metal seal integrity can be externally tested. Typical size and pressure rating values of collet connectors range from 3" API 10000 to 36", ANSI 900 class (i.e. 900psi in ambient temperature conditions). The collet connector is probably the most cost-effective connector and has been extensively used in the Gulf of Mexico deepwater developments; it is manufactured by: • Oil States/Hydrotech • Cameron • Kongsberg Offshore (FMC)


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Figure 3.2 - Collet connector, by courtesy of Hydrotech 3.3

Clamp connector Leak test port

Clamp connector

2" service line Alignment pins

Hydraulic & chemical lines

Floating jaws Jacking screw

Multibore seal plate Figure 3.3 - Multibore clamp connector (clamp and seal plate), by courtesy of Kvaerner Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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This system consists of a clamp assembly, a seal plate and two mating hubs. The clamp assembly may be a two jacking screw type (and consists of upper and lower clamp halves) or a single jacking screw type (see the above Kvaerner's clamp connector with a multibore seal plate, fitted with guiding pins for precise alignment, and the leak test port, passing through the clamp, which also plays the role of seal plate retainer). The two hubs are welded to the line extremity sections; their bodies are machined to receive the yoke assemblies of the connection tool and a male/female tapered entrance profile on the two hub faces provides the final precise hub alignment in preparation for clamp make up. The seal plate geometry is adapted to mate the two hubs and eventually equipped with guiding pins if the connection is a multibore connection in order to perform precise alignment.

Figure 3.4 - Two bolt clamp connector scheme, by courtesy of Grayloc products


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Figure 3.5 depicted the clamp connector principle; it consists in applying a radial force via the clamp (by tightening the clamp bolt(s) ) on the two hubs which hence mate (due to the clamp hub interface shape) and tighten the seal ring. Performing a connection with a clamp connector mainly consists in: • mating the hubs and the seal plate with a stroking system. If the connection is made-up with an ROV-mounted tool system, the clamp assembly is deployed with the subsea module and the seal plate is inserted by ROV tool; if the connection is made-up by an ROT, both clamp and seal plate are deployed together with the connection tool. • closing the clamp by tightening the screw(s) with a torque tool. Torque force and number of turns are monitored. • performing the seal test. A stab provides a pressure test line into the seal annulus.

Test port

Bolts Figure 3.5 - Two bolt clamp connector, by courtesy of Kongsberg Offshore The clamp connector is the main connector used in all major deepwater oil regions (i.e. North Sea, Brazil, Gulf of Mexico, West Africa, etc.) due to its robust construction and reliability. 20" rigid pipeline connections have already been performed in the North Sea using clamp connectors. Clamp connector can be provided for almost any diameter in accordance with the API 5L specifications and up to 5000psi (if required). The main manufacturers are: • • • •

Grayloc products (a division of ABB Vetco Gray Inc.) Cameron (McPAC clamp and seal plate systems) Kvaerner Oil Products Kongsberg Offshore (FMC)


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3.4


Petrobras triple line connector

Petrobras (and CBV manufacturer, a subsidiary of FMC) has developed a tie-in method and the associated hardware (X-mas tree and flowline hub) allowing the simultaneous lay of three lines (see "5.7 Vertical connection and triple lay").

Running tool Connection Service line Control umbilical

Guide pin TOP VIEW Flowline Torpedo (final guiding)

Chain (preliminary guiding) SIDE ELEVATION VIEW Figure 3.6 - Vertical Connection Flowline Hub, by courtesy of Petrobras The vertical connection method allow the tie-in of flexible flowline up to 12", service line up to 6". The vertical connection flowline hub weights about 2T. The hub includes a torpedo which is used as a guiding device and the subsea structure (i.e. production adapter base cradle, which receive the hub and the X-mas tree) is equipped with the corresponding funnel (receptacle, see following figure 3.7) which includes an helicoidal guiding device to orientate properly the hub. The upper part of the X-mas tree is equipped with the corresponding connector which is latched on the line hub during the X-mas tree landing operation. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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Connector (upper part with X-mas tree)

X-mas tree

Location for future vertical connector (see figure 3.6)

Production adapter base craddle

Receptacle funnel (for torpedo guide) Permanent guide base

Figure 3.7 - X-mas tree adapted to vertical connection (Marlim field), by courtesy of ABB Offshore Technology This tie-in method has a small drawback, i.e. the X-mas tree must be recovered should an intervention be required on the vertical connection flowline hub.


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3.5


Merlin connector

The Merlin connector is composed of two (inward and outward) hubs, both notched on the mating face. The connection operation consists in: 1. Stabbing of inward hub onto outward hub 2. Injecting pressured fluid within the two mating hubs while pushing them together with clamp jaws 3. Release pressure when inward and outward hubs are fully engaged The Merlin connector is available from 8" to 36". It has been used by Subsea Offshore Ltd. on the BP Harding field to fabricate a rigid pipeline: the pipe strings were laid on the seabed and then assembled by means of Merlin connector.

Figure 3.8 - Merlin connector


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3.6


Electrical connector

Figure 3.9 - CE connector, by courtesy of Tronic The prevailing concept for low and high power connectors since the 1980's is the fluid filled connector principle. Basically, the controlled environment (CE) plug concept removes seawater from contact with the critical components: • the electrical socket (female contact) is protected by its own oil bath, which in turn is protected by a primary oil filled chamber. The whole assembly is pressure balanced to minimise stress. • a shuttle pin prevents both water ingress and loss of oil when the connector is unmated. • during the connection, the male contact pushes on the shuttle and penetrates the oil filled chamber, being thus wiped clean of water twice before making contact with the electrical socket. The main electrical subsea mateable connector manufacturer is Tronic which has in particular developed a 11kV, 400A rated connector; this connector has been tested as part of the GEC Alsthom SPEED (subsea power electrical equipment distribution) project which allowed to test a 1MVA subsea power station rated for 300m during seven months. Electrical connectors are used for power, control and data transmission as further detailed in document "Umbilicals" which is part of the deepwater field development reference book.


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4


TIE-IN TOOL TECHNOLOGY REVIEW

4.1

General

The pull-in and connection systems can be divided in two types: 1.

Remotely Operated Tools (ROT). These autonomous ROT systems can be: ∗ two-tools tie-in systems (a pull-in tool and a connection tool) or single tool systems which combined all the functions. A pull-in tool is designed to pull the line in the structure through a serie of guides or funnels, lock the line on the structure, release the pull-in head and remove the debris cap; the functions of a connection tool are to position the line hub, perform the connection and carry out seal tests. ∗ designed for guideline or guidelineless installation method. ∗ with subsea winch integrated within the pull-in tool, or linear winch on ROT and cable storage drum on tie-in vessel. 2. ROV-mounted pull-in and connection tools

Above types of tools reflect the historical evolution of the tie-in tool technology: • • •

the first generation was composed by two ROT system (one pull-in tool and one connection tool) single tool ROT, combining both functions of pulling and connecting, were designed as an evolution of the first generation ROV-mounted tools represent the latest improvement for deep to ultra deep water depths.

All the connector types (as previously reviewed) can be potentially used with both ROVmounted tools and ROT.


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4.2


Remotely Operated Tools

Almost every SPS manufacturers / subsea contractors have developed their own ROT: • • • •

Kvaerner PICT Kongsberg UTIS, etc. Cameron DISPS and McPAC Hydrotech

The ROT system can be either two tools deployed independently, one for initial pull-in operation and one for the connection phase, or one single tool combining both tie-in sequence. The design maximum operating depth of such type tie-in tool is about 500m. They are able to handle both rigid and flexible lines. The main tools and their characteristics are described hereafter: • Cameron McPAC. The McPAC two-tool pull-in and connection system uses a drillpipe deployed pullin tool to pull a flowline or umbilical onto a porch structure by means of a surface winch cable, then the connection tool connects the line with a 2-bolt clamp and seal plate assembly. The McPAC system has been used several times on projects such as Shell/Esso UMC (UK North Sea), Placid's Green Canyon 29 and Enserch's Mississippi Canyon 441. Flowline sizes: Pull-in tool design water depth: Pull-in tool dimensions (WxBxH): Pull-in tool weight: Connection tool design water depth: Connection tool dimensions (WxBxH): Connection tool weight:

up to 16" (flexible and rigid pipe) 460m 4m x 3.3m x 5.6m 25.5ton 850m 3.2m x 1.2m x 2.9m 3.7ton

• Kvaerner "TOGI tools" As per above method (drill rig + lay ship), Norsk Hydro TOGI (Troll Oseberg Gas Injection project) 20" gas trunkline was pulled and tied-in, in 1991, with two ROTs manufactured by Kvaerner: ∗ PLT: Pull-in and Lockdown Tool ∗ UCT: Universal Connection Tool


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Clamp

Seal ring

Figure 4.1 - Pull-in and lockdown tool Figure 4.2 - Universal connection tool Maximum pipe diameter: PLT dimensions (WxBxH): PLT weight: Maximum pull-in force: UCT dimensions (WxBxH): UCT weight:


20" (rigid pipe) 3.4m x 2.4m x 4.2m 34ton 60 / 120ton 2.9m x 2.7m x 3.9m 28ton

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• Cameron DISPS pull-in and connection system. This two-tool pull-in and connection system has been developed by Cameron as part of BP Exploration's DISPS project. It is run on drillpipe and includes a pull-in tool, a connection tool, a clamp connector and a piggable termination cap. Flowline sizes: Design water depth: Pull-in tool size (WxBxH): Pull-in tool weight: Connection tool size (WxBxH): Connection tool weight:

up to 12" (rigid pipe) 730m 2.4m x 2.2m x 4m 9.2ton 2.4m x 2.2m x 4m 14.8ton

• Kvaerner PICT (Pull-In and Connection Tool). The PICT is a single trip tool that combines the pull-in, by means of linear winch and pull-in cable coming from surface, and connection functions. The benefit, against two tool systems, is saved operational time related to less launching and recovery time. It is a field proven system that has been used extensively on Norsk Hydro Troll (approximately 300m) development for tie-in of ISU umbilical and up to 10" flexible flowline. Linear pullin winch ROV panel

Funnel

Clamp Bull nose retrieval

Torque tool for clamp tie-in

Figure 4.3 - Pull-In & Connection Tool (PICT), by courtesy of Kvaerner Maximum pull-in capacity: PICT main dimensions (WxBxH): PICT weight (in air): Flexible pipe size: Water depth:


30ton 3.2m x 3m x 4.5m 10ton 10" (maximum) 500m

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• Kongsberg UTIS. The Kongsberg Offshore Universal Tie-In System (UTIS) is a combined pull-in and connection tool, designed to perform connections of steel lines of up to 14" OD and flexibles of up to 12" ID. It has successfully performed ten tie-ins of flexible flowlines at Zaphiro field phase 2 (500m). It was also used for tie-ins on Statoil Statfjord north and east or Saga petroleum Snorre fields.

Figure 4.4 - Universal Tie-In System (UTIS), by courtesy of Kongsberg Maximum water depth: Pull-in force: Pull-in speed: Max. stroking force capacity: UTIS footprint: UTIS Height: UTIS weight (in air): UTIS weight (in water):


2500m 40ton 0 – 15m/min 65ton 1.4m x 1.8m 4.9m (including tool control unit) 14.4ton 12.4ton

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• Exxon Zinc pull-in and connection system This system was developed to connect the two 8" export flowlines and the 4" service line to the Zinc subsea template. It is able to perform pull-in, connection and pressure testing using subsea winch and ROV-conveyed modules (i.e. neutral buoyant connection tool to be positioned by ROV). Flowline sizes: Design water depth:

<10" (rigid pipe) 460m

Figure 4.5 - Exxon Zinc pull-In & connection system, by courtesy of Hydrotech 4.3

ROV-mounted pull-in and connection systems

The ROV mounted pull-in and connection systems are typically composed of a pull-in and connection tool which can be deployed independently from the ROV, an interface skid which is mounted on the ROV and a tie-in porch which interfaces with the subsea structure. All these tools can be operated by means of a working class ROV deployed from a standard ROV support vessel. The ROV mounted tools have the following general characteristics: • • • •

Maximum pull-in force: Pull-in distance: Angular alignment: Tool weight:

30ton from 3m to 40m +/-15° 8-10ton

They are able to handle flexible lines up to about 20" and small diameter rigid pipelines (depending on the required pull-in force).


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The main contractors/ROV mounted tools are: • Coflexip Flexconnect (for flexible pipe from 1.5" to 19") • Sonsub DFCS (for flexible pipe from 4" to 16") • Kvaerner RTS (for flexible pipe up to 10") • ABB Icarus • Subsea Dmac (for flexible pipe from 4" to 12") • Kongsberg RPC (for flexible pipe up to 10") • Coflexip Flexconnect. The Flexconnect system has successfully completed its onshore and offshore trials (end 97 – early 98) and is now considered as part of the Coflexip project proposals for deepwater developments. It consists in an ROV-operated connection system, composed of a services skid (deployed with the ROV) and a pull-in module (wet mated to the services skid), which would accommodate water depth up to 2500m and flexible flowline sizes from 1.5" up to 19". The interface between the subsea structure and the system is performed by means of a cassette bay, which includes the clamp used to connect the two hubs.

ROV

Services skid Pull-in module Cassette bay

Flexible flowline Flowline hub

Figure 4.6 - ROV-mounted tool Flexconnect, by courtesy of Coflexip Stena Offshore


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Figure 4.7 - Services skid integrated

Figure 4.8 - Flexconnect Pull-In

to TRITON XL 17

Module (PIM)


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• Subsea DMac. The "Fuel Subsea Engineering & Costain" tie-in system is designed for 1500m water depth and flowline sizes up to about 12". It consists in a ROV tool (including torque tools, seal plate replacement tool, hot stab and pressure test tool), a line pull-in tool, interface skid and connection porches mounted on subsea structure. It has been used for Foinaven's tie-ins.

Figure 4.9 - ROV-mounted tool DMac, by courtesy of Subsea Offshore Ltd.


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•


Kvaerner RTS The ROV operated Tie-in System (RTS) consists of a pull-in and connection tool mounted on a standard work class ROV via the ROV interface skid. This tool is composed of the following main items: ∗ ∗ ∗ ∗ ∗ ∗ ∗

Pull-in winch with pull-in rope and anchor Jack screw torque unit Termination orientation system Termination lockdown system Receiver funnel Outboard hub alignment clamps ROV panel

ROV Pull-in module Clamp connector

SPS guide posts

Figure 4.10 - ROV-operated Tie-in System (RTS), by courtesy of Kvaerner Oil Products Flexible flowline size: Design depth:

up to 10" (can be upgraded) 1000m (can be upgraded)

The Kvaerner RTS have been used on Norsk Hydro Njord (1998) and planned for Visund (1999).


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• ABB Icarus ABB has developed an ROV mounted pull-in and connection tool similar to the above Kvaerner RTS. The Icarus pull-in system is planned to connect the jumpers on the Chevron's Kuito field in Angola.

Figure 4.11 - ROV mounted tool Icarus, by courtesy of ABB Offshore technology • Sonsub DFCS (Deflect and Connect System) The DFCS is a tooling package powered and operated by work-class ROV. It is used to retrieve, pull in and connect pre-laid subsea flowlines or umbilicals. The Sonsub system has performed three tie-in operations (two 13.5" and one 6" flowlines) in 310m water depth at Amoco's Liuhua 11-1 field and is planned to perform 19 flowline and four umbilical tie-ins at Esso Norge's Balder field in 19981999.

Figure 4.12 - ROV-mounted tool DFCS, by courtesy of Sonsub Flexible flowline: Water depth:


up to 16" 500m

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• Kongsberg RPC (ROV Pull-in and Connection system) The Combined Pull-in and Connection tool is designed to handle 10" 6000psi flexible and umbilicals; the maximum water depth is 2500m. The system is composed of: ∗ the pull-in skid including dual pull-in winches ∗ a collet connector, actuated by components internal in the tool skid ∗ a flexible termination assembly ∗ an inboard hub

Figure 4.13 - ROV-mounted tool RPC, by courtesy of Kongsberg The system main features are: Pull-in skid size: Pull-in skid weight: Maximum pull-in force:


2.8L x 1.7W x 0.85H 2ton 15ton

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4.4


ROV-mounted connection systems

Some tie-in operations based on direct stab-in of the connector require a much simpler ROV mounted tool, since the pull-in winch system is not required anymore. These tie-in operations can be basically described as follows: • • •

a rough positioning of the outboard hub is performed by means of hub's torpedo mating the corresponding funnel (for further details, see section 5.5 "Vertical stab, hinge-over and lay-away") then the ROV-mounted connection tool aligns and mates the two hubs (outboard hub is translated by tool onto the inboard hub) the connection is performed (with either a collet or clamp connector)

Figure 4.14 further depicts the ROV-mounted connection tool operation (herein represented with a clamp connector).

Connection tool

Inboard hub Clamp connector

Outboard hub Torpedo Funnel

Figure 4.14 - ROV mounted tool connection sequence


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Figure 4.15 - Connection as performed by a ROV mounted tool The ROV mounted connection tools are available from the main SPS contractors such as: • Cameron • Kongsberg Offshore • ABB offshore technology This tie-in method is valid for: • • • • •

flexible and rigid pipe: all diameter (API 5L) water depth: limitation only with ROV depth capabilities first end initiation and lay-away flexible jumpers rigid spool jumpers

and have been used mainly in GOM (BP Pompano, BP Troika, Shell Mensa).


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4.5


"MATIS" API flange tie-in tool

Stolt Comex Seaway (SCS), and partners Hydra-Tight Ltd. and National Hyperbaric Centre Ltd., developed the Modular Advanced Tie-In System (MATIS). This unique tool is designed to be deployed and controlled by ROV and to perform the tie-in of 10" class 1500 bolted flanges. MATIS allows to load all bolts simultaneously and to check the residual bolt load and distribution without diver intervention (design water depth: 1000m). To date, no field tie-in have been performed using this tool.

Figure 4.16 - MATIS, by courtesy of Stolt Comex Seaway


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5


TIE-IN METHODS

5.1

General

This chapter will review the existing tie-in methods, which have been used, or could be used in deepwater applications. Tie-ins are mainly required between subsea structures such as: • between X-mas trees and manifolding systems • between manifolding systems and PLEMs • between PLEMs and riser bases Basically all diverless and guidelineless connector systems (as reviewed in the previous chapter) can be used to perform a connection. However the selection of a tie-in method must be based on the following key topics: • • • • • • • •

the field subsea architecture (number of tie-in points, manifold, PLEM, etc.) the water depth the seabed conditions (i.e. soil type, visibility, current, etc.) hydrocarbon product temperature, pressure and chemistry the connection technology (mechanical, electrical, monobore or multibore) the line type (i.e. rigid pipeline, flexible or umbilical) and its diameter availability and cost of the selected connector, tie-in tools, etc. the SPS manufacturer, which can propose its own connection tool, adapted to its subsea production system and connector technology.


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5.2


Lay-down & pull-in

5.2.1

Description

Figure 5.1 - Pull-in principle Connection's type

Sealine - subsea structure

line's type

Flexible line Umbilical

vessel(s) required Separated operations: • Laying vessel • Tie-in vessel (with ROV and adequate deck space for pull-in tools)

The lay down and pull-in method consists in pulling in and connecting a flowline or umbilical, pre-laid down on the seabed in a predetermined target area, to a subsea structure (X-mas tree, manifold, riser base). This method is effective for both first end and second end extremity connection of flowline to subsea structure. Typical pull-in force expected for such an operation is about 5-10T, depending on the line type and soil conditions (friction coefficient) and a pull-in distance to be limited to less than 50m. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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5.2.2


Tie-in procedure

The lay down and pull-in operation can be divided in three phases: 1. The flowline or umbilical end extremity (first or second) is equipped with a pull-in head. The termination head is laid on the seabed within a target area by a lay vessel. Several laying configurations can be adopted near the connection point: ∗ line approaching the structure along a straight-line oriented towards the connection point but with sufficient downstream "slack" line for future pull-in operation. ∗ line laid in curve near the structure (flexible or umbilical lines) in order to decrease the pull-in tension. ∗ off-centred straight-line configuration in order to perform a lateral deflection during the pull-in operation. 2. The pull-in operation is then performed by a smaller vessel (i.e. tie-in vessel) equipped either with (1) an ROV-mounted pull-in tool or (2) an ROT/pull-in system remotely operated from surface tie-in vessel. The pull-in tool function is to place the line's hub connector closed to the subsea structure's hub (it generally includes a guiding device such as a funnel, to perform a rough alignment) and to prepare the connection operation (the debris cap is retrieved, etc.): ∗ with an ROV-mounted tool: the tool package is fixed on ROV which then attaches the pull-in rope on the subsea structure pull-in porch, clamps itself on the pull-in head of the line and performs the pull-in operation. When the head is closed to the connection point, ROV prepares the hubs (debris cap removal, etc.) and performs the connection prior to the seal test performing. ∗ with a Remotely Operated Tool: the pull-in tool is lowered and fixed on the subsea structure; ROV attaches the pull-in rope, then the line's head is pulled toward the connection point and aligned at the final stage by guiding devices on the tool. After the pull-in operation, the connection is performed if the tool is a two-tool system, otherwise the pull-in tool is recovered onboard and the connection system is lowered. 3. Finally the line is connected to the subsea structure with: ∗ either the same ROV-mounted and combined connection tool ∗ or an ROT/connection system remotely operated from surface tie-in vessel The connection is typically performed by means of collet connector or clamp connector in combination with a seal plate. External leak tests (nitrogen or hydraulic) are then performed by ROV or ROT means to check the connection.


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5.2.3


Utilisation and limitations

The lay-down and pull-in method has been extensively used in most oil provinces but mainly for shallow water depth applications (200 - 400 msw). Petrobras has experienced this method with no satisfactory results (i.e. near seabed ROV operation on soft soil). The ROT based connection systems utilising a surface-operated winch become unsuited as the water depth increases due to the number of lines running from surface (lifting line, pull-in cable, umbilical). For deepwater operation, the ROV-mounted tools (e.g. Flexconnect, RTS) are better adapted. The “lay down and pull-in” method requires good seabed conditions: • good visibility by cameras (and ROV) near seabed • seabed clear of any debris within the pull-in pattern • low soil shear force coefficient to ease the pull-in operation, but still consolidated soil bearing to prevent pull-in head diving into the mud-line. This tie-in method is therefore not recommended for deepwater connection in the case of very soft soil conditions (i.e. 5-15kPa) and poor visibility near seabed.


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5.3


Direct pull-in

5.3.1

Description

Figure 5.2 - Direct pull-in Connection's type

line's type

vessel(s) required

Sealine - subsea structure Riser - subsea structure

Rigid pipeline Flexible line Umbilical

Combined operation of Laying vessel and Tie-in vessel equipped with pull-in tool

The direct pull-in method consists in connecting a flowline or an umbilical to a subsea structure (manifold, tree) by pulling it directly to the tie-in point in order to: • either initiate the laying operation. The line is pulled off the laying vessel to the subsea structure, latched and then the laying vessel continues the laying operation. The connection is then performed when the laying sequence ends. • or connect a flowline that has been towed from an onshore fabrication yard. the pull-in is performed to help controlling the lowering of the line and allows to adjust the first end position to perform the connection. For the pull-in, a cable coming from a surface winch or subsea winch can be used and then the connection is performed by a separated tool. This method is effective for first end tie-in of umbilical, flexible and relatively small diameter rigid line. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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5.3.2


Tie-in procedure

The main phases of a direct pull-in can be basically described as follows: 1. Setting of the pull-in tool on the subsea structure 2. Attachment of the pull-in cable which runs from the pull-in tool to the line to be laid and connected. 3. Lay initiation of the line: the line is pulled towards the subsea structure while being paid out from the laying vessel. The catenary curve is controlled by monitoring the line pull-in head position, by means of transponders, and tension in order to avoid any buckling problem. 4. When the line pull-in head arrives at the subsea structure, the pull-in tool latched it, allowing to start the nominal laying mode. 5. The connection is then performed by the adequate tool(s). 5.3.3


The direct pull-in method allows to perform the initiation of a line laying without using a PLEM, anchor or another supplementary item because the subsea structure is used as an anchor point. This involves to take the pull-in loads into account for the design of the structure. This method is very effective for flowline initiation with however two main drawbacks (see chapter 6 "Advantages and disadvantages"): • it requires the availability and good coordination of two vessels. • the connection cannot be performed until the end of the laying operation where the flowline is “pigged” and flooded. The “Direct pull-in” method is limited by the design maximum water depth operability of the pull-in tool (i.e. about 300m-500m) and has been used on Nork Hydro TOGI for up to 24" rigid sealine.


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5.4


Deflect-to-connect

5.4.1

Description

Figure 5.3 - Deflect to connect principle

Connection's type

line's type

vessel(s) required

Sealine - subsea structure

Rigid pipeline

ROV support vessel with adequate subsea lift

This method consists in lifting a defined length of a pipeline (typically 500m – 800m) by means of buoys, deflecting the line end near the structure with a vessel or subsea winches and finally pulling the line to the subsea structure in order to perform the connection. The deflect-to-connect method is effective for rigid pipeline tie-in to a subsea structure. The pipeline must have been laid along an off-centred straight line near the structure prior to the deflection (typical distance 100m – 200m).


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5.4.2


Tie-in procedure

A typical deflect-to-connect operation can be described as follows, the procedure starts when the sealine is laid in the predefined configuration: 1. When the preparatory works are performed (survey of the seabed, check of the equipment, etc.), air bags (or buoyancy elements) are fixed to pre-installed collars (Troll Olje method) and inflated in order to lift the future deflected length of pipeline (fixed by the required final curvature). Drag chains (installed during pipelay operation) spread along the lifted length are used to control the height of lifting and the pipeline curve during the deflect operation (by varying the chain length friction with seabed and so controlling the drag forces at different points of the deflected length of pipeline). The deflected length is also equipped with transponders to check the elevation and the pipe curvature during the deflect operation. As an example, about 15 air bags and 5 transponders were spread along the 400m – 500m of deflected pipeline on the Troll Olje project. 2. The sealine is deflected: • either by a vessel which displaces a dead weight attached to the pipeline extremity toward the subsea structure (Elf East Frigg and Norsk Hydro Troll) • or by subsea winches mounted on the subsea structure (R.J. Brown method) This is done by steps of approximately 10-20m until the pull-in head is in front of the subsea structure; the pipeline curvature is checked at each step by means of transponders and compared to the theoretical values (the minimum bending radius and line tension must always be controlled to avoid any local buckling, etc.). 3. When the pull-in head is in front of the subsea structure, a pull-in and connection operation is performed by ROT: • • •

5.4.3

after the pull-in operation and once the pipe is secured inside the subsea structure, the pipeline can be flooded on completion of pipe flooding, the connection can be performed on completion of the tie-in task, all installation riggings are recovered (chain, buoyancy elements, etc.)


This method is mainly used to connect large diameter rigid pipeline because of the difficulty to manipulate and connect them with another method. The sealine final curve must also consider the service conditions, in terms of temperature dilatation, possible slugs, etc. Besides these technical issues there is no foreseeable limitation for deepwater applications. Several diverless deflect-to-connect operations has been successfully performed including the two 16" ID export lines on Norsk Hydro Troll B project and the two Elf East Frigg 24” bundles. Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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5.5 5.5.1


Vertical stab, hinge-over & lay-away Description

1

3

2 STAB-IN

CONNECTOR LOWERING

HINGE OVER

4

CONNECTOR IN FINAL POSITION

Figure 5.4 - Vertical Stab and Hinge over principle

Connection's type

line's type

vessel(s) required


Small diameter rigid pipeline Flexible line Umbilical

Separated operations: • Laying vessel • Tie-in vessel

This tie-in method is used to initiate flowline or umbilical first extremity by stabbing and latching it (by means of a hinged torpedo) in a receptacle (i.e. funnel) mounted on the subsea structure (manifold, tree, PLEM). The connection is performed after the laying operation by means of an ROV-mounted connection tool (see chapter 4.4).


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5.5.2


Tie-in procedure

Prior the nominal laying operation, the line first extremity is lowered down and latched to the subsea structure by the stab and hinge over method: 1. The stab and hinge over assembly is connected to the line (flowline or umbilical) and a transponder is attached to position the line termination during initiation. 2. The assembly is lowered at the vertical position of the subsea structure receiver. While setting up in DP over the tie-in point, the laying vessel continues to pay out the line. The stabbing of the assembly into the receptacle funnel mounted on the subsea structure is performed; the final approach is assisted by ROV. An orientation helix in the receptacle rotates the head into the proper rotational alignment for the hinge over. 3. When the assembly is fully engaged and locked in its receptacle, the laying vessel moves ahead slowly while paying out the line until the line is correctly landed on the seabed. The laying operation continues. 4. At completion of the laying operation (i.e. pipe flooded), the connection (by a tiein vessel) is performed by stroking out the hub or connector that is retracted during the stab and hinge over operation and then connecting it to the subsea structure (see chapter 4.4). 5.5.3


This tie-in method is effective for rigid, flexible and umbilical lines but attention must be paid to the rigid line stabbing and initiation loads. A minimum flexibility of the line is required during the stab step of the method, particularly if no heave compensator is used. This method is probably the most cost effective solution to perform the fist end initiation and tie-in for deepwater applications. No water depth limitation is expected (i.e. the only limiting factor is the connection tool maximum water depth operability, which is today about 2500m). The only limitation is with large diameter rigid pipeline due to potential high load on the subsea structure during the stabbing and hinge-over phases, although passive heave compensated tensioners would annihilate this limitation. This method has for example been used to connect 6" flowlines and umbilicals to manifold on the Shell's Mensa field (1620m); hydraulic connectors powered by ROV via an ROV interface panel were used.


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5.6


Surface tie-in, lay-away & lay-to

5.6.1

Description

This method, developed by Petrobras, was used up to 1992 and was then replaced by the vertical connection method (see chapter 5.7).

Figure 5.5 - Lay-away principle, by courtesy of Petrobras

Connection's type

line's type

vessel(s) required

Sealine - subsea tree Riser - subsea tree

Flexible flowline Umbilical

Combined operations with a Laying vessel and a Drilling rig

The lay-away and lay-to surface tie-in method is effective to connect first or second end of a flexible and umbilical line to a subsea tree. This method consists in performing the connection between the line and the X-mas tree onboard a drilling rig prior to the lowering of the assembly.


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5.6.2


Tie-in procedure

The lay-to or lay-away methods, which have been primarily developed by Petrobras to improve existing pull-in methods, can be described as follows. The lay-away tie-in procedure can be divided in five main phases: 1. After arriving on location, the laying vessel positions itself approximately 30m away from the drilling/completion rig. A cable is passed from the rig to the laying vessel (e.g. by means of a messenger line) and attached to the flowline(s) (the number of flowlines depends on the laying vessel capacity) first extremity equipped with a pulling head. 2. Each flowline first extremity is transferred to the rig by paying out the line while pulling the cable according to a predefined sequence. 3. When the predetermined catenary curve is achieved, each flowline first extremity is connected to the subsea tree onboard the drilling rig. The assembly is fully tested, allowing the eventual problems to be solved prior the laying operation. 4. The tree and the flowlines are then lowered simultaneously. The tree is landed and connected. 5. When the connection is pressure tested, the nominal laying mode can start: the flowlines are laid by the laying vessel towards the production floater. The lay-to operation applied the same philosophy: 1. While laying the flowline(s), the laying vessel arrives near the drilling/completion rig. When the line(s) second extremity is fully secured on the working table of the laying vessel, a transfer cable is passed from the rig (e.g. by means of a messenger line) and attached to it. The flowline second extremity is transferred to the rig by lowering it by means of an abandonment cable while pulling the transfer cable according to a predefined sequence. A second option is that the line is lowered by the laying vessel on the seabed in an extended loop arrangement and later recovered by the rig by means of a lifting cable attached to the flowline extremity by ROV. This method avoids the problem of the simultaneous presence of the laying vessel and the rig. 2. The flowline(s) second extremity is then connected to the tree onboard the rig. The assembly is fully tested, allowing the eventual problems to be solved prior the lowering operation. A cable (from the laying vessel) is then attached at a defined intermediate location on the flowline(s). 3. The drilling rig lowers the tree while the laying vessel retains the line(s). As the drilling must be located at the vertical position of the well during the operation (if guidelines are used to install the X-mas tree), a flowline overlength (at least equal to the water depth) is required. 4. Once the tree is landed and tied-in, the vessel lays the loop on the seabed.


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5.6.3



The main advantages of this method (see chapter 6 "Advantages and disadvantages") are clearly to allow the connection and all tests to be performed in surface. The lay-away method was a standard for diverless connections in Campos Basin up to 1992 where 57 lay-away operations, including 36 guidelineless operations, have been successfully conducted in water depths ranging from 280m to 1030m. Then the vertical subsea connection system (see section 5.7) was developed to overcome its drawbacks (mainly the obligation of the presence of both drilling rig and laying vessel and also the fact that only connections to subsea trees are possible).


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5.7


Vertical connection and triple flowline lay-away

5.7.1

Description

The vertical connection method was developed to overcome the drawbacks of the surface tie-in, lay-away and lay-to method (see chapter 5.6).

Figure 5.6 - First end Direct Vertical Connection principle Connection's type

line's type

vessel(s) required


Flexible line Umbilical Bundle

Laying vessel

The vertical connection was developed by Petrobras to allow connection of flexible lines to any subsea structure with no requirement for the simultaneous presence of drilling rig and laying vessel.


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Initially the vertical connection was developed with a temporary abandonment base for the first end termination, with the following operation sequences: 1. The laying vessel lays the line with its hub connected to a temporary abandonment base on the seabed. The hub is positioned closed to the subsea structure (tree or manifold) to be later connected. The laying vessel can leave the site. 2. The drilling / completion rig retrieves the hub from the temporary abandonment base and installs it onto the production adapter base cradle. Then, the tree is run and locked simultaneously on the production base housing and flowline hub. This vertical connection system has been used extensively since 1992 (more than 30 successful operations in Campos Basin), but the direct vertical connection system was then developed to improve operational efficiency and to eliminate the need for a temporary abandonment base, which implies additional installation costs. Because the laying vessel lowers and directly locks the flowline hub to the structure (both tree and manifold), the direct vertical connection system allows first end and second end connections without using a temporary abandonment base. The flowline itself or an auxiliary cable is used as string for the lowering operation, the principle of this method being to perform the connection with the help of a torpedo mounted on the bottom of the line hub (see previous section 3.4 ″Petrobras triple line connector″). 5.7.2

Tie-in procedure

Only the direct vertical connection method is described here as it is considered as a more advanced connection method. The main steps of a direct vertical connection procedure are: 1. The laying vessel is positioned over the subsea structure. Transponder is fixed on the lines (or bundle) first extremity equipped with vertical connection head. 2. The assembly is lowered over the tie-in point. While setting up in DP over the subsea structure, the laying vessel continues to pay out the lines. The final approach is assisted by ROV and consists in stabbing the torpedo into the production adapter base cradle. The lines are orientated by the passive orientation system included in the receptacle. 3. When the assembly is fully engaged and locked in its receptacle, the laying vessel moves ahead slowly while paying out the lines until they are correctly landed on the seabed. The laying operation continues. 4. The connection is then performed after the landing of the X-mas tree by the drilling rig.


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5.7.3



The direct vertical connection method allows the initiation of bundles; the average flowline stabbing and locking time is 2-3 hours, which can be considered as excellent. In 1996, the first direct vertical connection was performed on the Albacora manifold in 620m water depth; up to now, more than twenty direct vertical connections (first end and second end connections) were performed in the Campos Basin. This method allows simultaneous laying of up to three lines (e.g. production line, service line and control umbilical) which are connected to the structure by multibore hub and sealplate. This vertical connection combined with the lay-away of bundles in one lay sequence represent the most cost effective solution for deepwater la y operations. However in the case of a second end connection requirement, some difficulties have been experienced during the torpedo stabbing into the receptacle due to: • • • •

flexible lines stiffness (flowline length adjustment) torpedo receptacle alignment angle (i.e. seabed level) current drag effect vessel heaves


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5.8


Flexible jumpers

5.8.1

Description

Figure 5.7 - Flexible jumper principle Connection's type Sealine - subsea structure Riser - subsea structure Tree - manifold

line's type

vessel(s) required

Rigid and Flexible flowlines

Vessel equipped with ROVs and lifting capacities

Umbilical

The principle of this method is to perform the link between two subsea structures (tree and manifold) or between a subsea structure and a line end termination (PLEM) by means of a flexible jumper. The distance between the two connection points, and hence the length of the jumper, is conventionally about 20m - 50m (i.e. within most medium size vessel lifting capacity). 5.8.2

Tie-in procedure

Flexible jumpers can be used for vertical or horizontal connection method. The flexible jumper installation method depends on the connector type but it can basically be described as follows: • with horizontal connector (either collet or clamp connector), the jumper is typically laid down on the seabed in the connection area and then connected by the pull-in method. • With vertical connector (i.e. collet connector. cf. figure 5.7), the jumper can be installed with a spreader bar and with upward facing mandrel vertical connectors located on subsea structure. • the stab and hinge over method can also be used; this type of tie-in was utilised to perform the connection of flexible jumper for Shell's Rocky field: the first end was equipped with a "Stab & hinge over" type hub and the second end included a Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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vertical collet connector. After landing and locking of the first end, the second end was connected. This tie-in method is dependent on ROV operation for all phases from guiding, landing, docking to connection and leak tests. 5.8.3


Flexible jumpers are effective means to perform the connection between flowline end termination and subsea structure or between two subsea structures (i.e. tree and manifold). Flexible jumpers allow to withstand some imprecision in the position of line ends or subsea structures (and the eventual flowline dilatation); thus there is no drastic requirements concerning subsea metrology (unlike steel jumpers) and it is sufficient to position pipeline termination head and/or subsea structure within less stringent target boxes. Flexible jumper's diameter and water depth limitation are dictated by the flexible technology. The use of flexible jumpers for deepwater applications would be limited mainly by economic consideration.


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5.9


Steel jumpers

5.9.1

Description

Figure 5.8 - Steel jumper principle Connection's type Sealine - subsea structure Riser - subsea structure Tree - manifold

line's type

vessel(s) required

Rigid and Flexible flowlines

Vessel equipped with ROVs and lifting capacities

Umbilical

Steel jumpers are 20m to 50m long rigid spool piece which perform the connection between a PLEM and a riser base or a subsea structure, or between two subsea structures. They are typically U or inverted-U shaped, depending on the required flexibility (360° loops acting both as expansion loop and spring could also be added in the jumper) and are either vertical or horizontal connection types. 5.9.2

Tie-in procedure

Accurate measurements are required before steel jumper fabrication, either on shore or on board the laying vessel (or barge, etc.). These measurements aim to define the relative position of both jumper's ends future location (distance and inclination between the two connection points) in order to define its final dimensions and to allow quick and hazardless installation. These measurements can be obtained by acoustic array or taut wire metrology (see chapter 7 "Subsea metrology").


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The main phases of a steel jumper fabrication and installation are described below; the considered connection can be either between subsea structure(s) and/or flowline termination(s): 1. When the subsea structures or flowline terminations have been laid over the seabed, their position is determined using acoustic transponders in order to: • check that they were laid within the target boxes (e.g. 5m x 5m) • determinate an approximate jumper length for pre-fabrication. That allows, if the jumper is fabricate offshore, to perform some cut and welds operations during a non-critical period of vessel use (e.g. during flowline hydrotest) and thus to reduce the final jumper fabrication time. 2. Accurate measurements of the jumper length and of the elevation differences between the two connection points are performed. This can be done by one or both of the following systems: • Extra High Frequency (EHF) acoustic transponder and digital quartz depth sensor • measurement tool which consists of a taut line, winch and protractors 3. After conversion of the detailed measurements into cut points and lengths, the final jumper fabrication can be performed either onshore or offshore (e.g. onboard a barge). 4. After fabrication, jumper geometry is verified by placing it on a fabrication jig. The jig is set up based on the measurements taken subsea and mocks the jumper receiver structures in order to verify that the jumper would mate with them. 5. The jumper is then transported offshore, lowered to the seabed and connected. This can be done by using a spreader bar or the stab and hinge over method which consists in: • • • •

lowering the jumper vertically stabbing one extremity of the jumper Stabbing the other extremity Performing the connection by ROV

Figure 5.9 - Steel jumper installation (Stab & hinge over method)


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Figure 5.10 - BP Troika field, steel jumper installation (spread bar and vertical connectors) 5.9.3


No diameter or water depth limitation is expected. The main advantage (see chapter 6 "Advantages and disadvantages") of the steel jumper is its economical aspect when combined with stringent heat insulation requirement. This point suffices to explain its extensive use in the Gulf of Mexico deepwater developments. 5.10 "Rigi-Flex" jumper A new tie-in product is being promoted by ABB Vetco Gray to be able to compete with both flexible jumpers and rigid spools, and is expected on the market by the end of 1999. It is designed to be more flexible (by 40 times) than a rigid spool while providing more protection/insulation and being less expensive (by 25%) than a flexible jumper. "Rigi-Flex" comprises a corrugated inner pipe surrounded by conventional casing in which series of slits have been cut. Vetco aims to have a range of spools from 4-14in in 12m lengths with the maximum assembled length of around 90m; the high-pressure and temperature applications are targeted, as the product is rated up to 410bar and 150°C. The terminations would be welded and the intention is to have a range of endfittings to make the spoolpieces compatible with most pull-in systems. The jumper can span between two subsea structures or lay on the seabed. There is no foreseeable water depth limitation.


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5.11 Hybrid steel pipe & flextail 5.11.1 Description

Figure 5.11 - Hybrid steel pipe and flextail principle Connection's type

line's type

vessel(s) required


Rigid pipeline

Laying vessel

This method consists in combining rigid and flexible line: a flexible tail is added to the rigid pipeline to be able to manipulate more easily the extremities during the tie-in phase. The philosophy can be considered similar to the flexible jumper method, as a flexible line is used to perform the connection between a rigid flowline and a subsea structure, but the flextail and the rigid flowline are connected in surface, simplifying this part of the tie-in operation and allowing to perform external connection leak tests prior to the lowering of the hybrid pipe. This method has been used mainly by Coflexip Stena Offshore for Petrobras (Roncador) in Brazil.


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5.11.2 Tie-in procedure The flextail is used to perform the connection between a rigid pipeline and a subsea structure. It can be installed as per one of the following methods: 1. The flextail can be installed as part of the rigid pipeline: at the end of the pipe laying, the flextail is directly connected onboard the laying vessel and then: ∗ either the connection between the flextail and subsea structure or riser termination is performed by the laying vessel. ∗ or the flextail is laid with the connector supported by an abandonment skid to be later connected. 2. The rigid pipeline is abandoned on the seabed and later recovered to connect the flextail prior to the connection between the flextail and the subsea structure or the riser base structure. 5.11.3 Utilisation and limitations An hybrid steel pipe and flextail can be used with the following restraints: • The rigid pipeline diameter is limited: flextail and rigid pipe must have the same internal diameter (e.g. pigging operation). • Flexible line must be designed for the considered water depth (i.e. reversed end cap effect: collapse of the steel armour under hydrostatic pressure) and the tension load induced by the rigid pipeline (air filled) during the abandonment operation. • Limitation is related to flexible line technology.


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6



The following table is a list of the main advantages and drawbacks of each tie-in methods: Tie-in Method Lay-down and pull-in (Flexible lines and umbilicals)

Advantages • Laying and connection operations are independent • First end and second end applications

Drawbacks • High pull-in loads may be necessary • Optimum seabed conditions • Limitations in flexible line diameter • Complexity and size of tools • ROV-mounted tools are dependent on ROV reliability

Direct pull-in

• Allows initiation without additional anchor

(Rigid and flexible lines and umbilicals) Deflect-to-connect (Rigid pipelines)

• First end initiation only • Coordination of two vessels • Laying and connection operations are independent • First end and second end applications

Vertical Stab, hinge over and lay-away

• Low installation loads transmitted to structure

• Initiation of the line and (Rigid and flexible lines preparation of the and umbilicals) connection are simultaneously performed Surface tie-in, lay-to & • Reliability of connections performed in surface lay-away • Connection tested prior to (Flexible lines and the installation umbilicals) • First end and second end applications


• High pull-in loads acting on subsea structure

TIE-IN METHODS

• Large area of unobstructed seabed is required • Longer tie-in operation

• Weather sensitive operation • Heave compensation could be required for the rigid flowline • First end initiation only • Only connections to subsea trees are possible: incompatible with subsea arrangement involving manifold which implies more than one connection • Simultaneous presence of both laying vessel and drilling rig

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Tie-in Method


Advantages

• Low installation loads Vertical connection transmitted to structure and triple flowline layaway • Initiation and preparation of the connection are (Flexible lines and simultaneously performed umbilicals) • Triple initiation and lay is possible Flexible jumpers

• High degree of flexibility • Only simple measurement of relative connections position

Drawbacks • Weather sensitive operation • Only flexible line can be considered • Difficulties during second end stabbing

• More expensive solution than steel jumper • Two subsea connectors are required per jumper

• Low load transmitted to structure • replacement of the jumper is possible without any impact on subsea equipment Steel jumpers

• simple and robust design • rigid pipeline heat expansion absorbed by spool piece • Better heat insulation • replacement of the jumper is possible without any impact on subsea equipment

Hybrid steel pipe & flextail

• High degree of flexibility • Low load transmitted to structure • Only one subsea connector is required

• Longer overall tie-in operation when considering subsea metrology operation • Accurate measurements of connections relative position • Large deck area is required • Weather sensitive operation • Two subsea connectors are required per jumper • rigid pipeline recovery, if required, is a critical operation • Water depth application is limited by the flexible technology

The above summary table has clearly established that there is no obvious or simple tie-in method that could be considered as the generic solution for deepwater applications. There is good range of alternative tie-in methods and only a thorough evaluation of all relevant field technical data, as further itemised in chapter 2 “Interface requirement”, can provide the most cost effective tie-in method and technology to be selected for each project.


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7


SUBSEA METROLOGY

7.1

General

Some subsea tie-in operations require accurate subsea measurements, especially steel jumper installation because it is necessary to precisely determine distance and angles between the two tie-in points prior to the final jumper fabrication. These measurements are generally made using two measurement tools in order to check the values; both "Acoustic Base Line" and "Taut Wire Metrology" described hereafter can be used as the primary measurement means. A premise for this method is that the subsea structures must be installed within the following tolerances: • • • 7.2

lateral position within +/- 5m of its nominal position heading of structure within +/- 2.5° maximum inclination relative to horizon within 2) in any direction.

Acoustic base line

Figure 7.1 - A typical transponder array A long base line (LBL) acoustic array is deployed on the seabed by ROV in the area of the jumper route. This array typically consists of up to six extreme high frequency (EHF) transponders: two are deployed on the seabed and two are placed at each tie-in point (a dual transponder arrangement at each tie-in point offers a better level of redundancy). The array is calibrated after the determination of the sound velocity in water from temperature / salinity measurements. Once the transponders are in position, the programmable acoustic navigator interrogates transponders to measure all baselines. A least squares analysis allows to determine the relative positions, orientations and distance of tie-in points. The relative height difference is determined using the pressure sensors in the transponders. To determine accurately the relative orientation between the tie-in points, the Rev. 0 30/09/2000 DGEP/SCR/ED/TA

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ROV can dock on the two points and measure the heading using a precision gyro (i.e. laser based gyro). This technique typically allows measuring better than +/- 5cm (over a 50m length) and 1° on relative headings. A typical metrology operation would be between 12 – 24 hours to include transponder deployment and recovery. 7.3

Taut wire metrology

Figure 7.2 - The pre-measurement tool A taut wire measurement tool typically consists of a taut line, winch and protractors with dual axis inclinometers. It is deployed and operated by ROV and a measurement operation consists in: • Installing the tool into the adapted receptacles. • Deploying the measurement cable by ROV and applying tension in the cable with the winch. • Measuring the vertical elevation difference and angular misalignment between the two tie-in points by the protractor and dual axis inclinometer readings. A resolution of 1° can be achieved. • Determining the distance between the two points from the length of the taut line. This length can be measured from a calibrated measuring wheel mounted near the winch. This counter can achieved an accuracy of +/-3cm (over a 50m length). The ROV video is used to document relative angles and distances between the two points. The measurements are normally repeated to verify values and to help to assess accuracy.


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8


TIME ESTIMATED FOR DEEPWATER TIE-IN OPERATION

The time required to perform a deepwater tie-in operation will depend greatly on key topics such as: • the choice of the tie-in method • the number of tie-in operations that can be performed in one installation phase (i.e. learning curve effect consideration) • ROV and ROT reliability and availability when required • experience and training of the ROVs and tie-in personnel • the water depth in terms of launching and recovery time based on an average descent and ascent speed of 800m - 1000m per hour Albeit the above criteria, the benchmark for deepwater tie-in operation could be defined as follows: • 24 hours - 36 hours for a stand alone or single tie-in operation • average of 6 hours to 12 hours per tie-in, in case of large number of tie-ins (e.g. more than 10 tie-ins) being performed within an installation campaign. The above timing is to be considered from spread arrival on site until completion of the tie-in operation, ready for departure to other location and without any major downtimes (i.e. technical and weather related).


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ANNEX 1 Manufacturers and Contractors List


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ABB OFFSHORE TECHNOLOGY

P.O Box 1200 N-4301 Sandnes Norway Tel : (+47) 51 60 37 00 Fax : (+47) 51 60 37 10

CAMERON

P.O Box 1212 77251-1212 Houston Texas Tel : 713 939 2211 Fax : 713 939 2620 http : //www.camerondiv.com

COFLEXIP STENA OFFSHORE GROUP

23, avenue de Neuilly 75116 Paris, France Tel : (+33) 1 40 67 60 00 Fax : (+33) 1 40 67 60 03

FMC CORPORATION Ltd

Wellhead Equipment Division Pitreavie Business Park Queensferry Rd Fife KY11 5PU Tel : 01383 731531 Fax : 01383 727250

GRAYLOC PRODUCTS

P.O Box 2291 77252-2291 USA Houston Texas Tel : 713-468-8853 Fax : 713-937-2335

HYDROTECH SYSTEM Inc.

11500 Northwest Freeway Suite 620 77092 Houston, Texas Tel : 713-688-5277 Fax : 713-688-9166

KONGSBERG OFFSHORE

P.O Box 1012 N-3601 Kongsberg, Norway Tel : (+47) 3273 9898 Fax : (+47) 3273 9378

KVAERNER ENERGY a.s

P.O Box 9277 Gronland N-134 Oslo, Norway Tel : (+47) 22 66 61 88 Fax : (+47) 22 66 64 00

OCEANEERING International, Inc.

11911 FM 529 Houston, Texas 77041, USA Tel.: 713-329-4500 Fax.: 713-329-4951 http : //www.oceaneering.com


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OIL STATES INDUSTRIES,Inc

P.O Box 670 7701 S. Cooper Street Arlington, Texas 76001 Tel : 1 817-468-1400 Fax : 1 817-468-6200 http : //www.oilstates.com

SONSUB

Broadfold Rd AB23 8EE Aberdeen Tel : 01224 706888 Fax : 01224 706705

STOLT COMEX SEAWAY AS

36, Boulevard des Oceans 13275 Marseille France Tel : 04 91 23 50 65 Fax : 04 91 40 72 75

SUBSEA OFFSHORE Ltd

Greenwell Road East Tullos AB1 4AX Aberdeen Tel : (01224) 292000 Fax : (01224) 879312

TRONIC

Sandside Road Ulverston, Cumbria LA129EF England Tel : (01229) 5850500 Fax : (01229) 589200


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DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK DEEPWATER ROV AND TOOLS


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TABLE OF CONTENTS 1

2

3

4

INTRODUCTION ........................................................................................................... 4 1.1

SCOPE................................................................................................................................4

1.2

REGULATION, CODES, STANDARDS & SPECIFICATIONS .........................................................5

1.3

DEFINITIONS & ABBREVIATIONS ...........................................................................................5

1.4

REFERENCES ......................................................................................................................6

1.5

ACKNOWLEDGEMENTS ........................................................................................................6

INTERFACE REQUIREMENT....................................................................................... 7 2.1

GENERAL ............................................................................................................................7

2.2

INTERFACE WITH SUBSEA STRUCTURES ...............................................................................8

2.3

INTERFACES WITH SUPPORT VESSEL ..................................................................................10

INTERVENTION PHILOSOPHY AND FUNCTIONAL REQUIREMENT ...................... 11 3.1

GENERAL ..........................................................................................................................11

3.2

INTERVENTION BY ROV.....................................................................................................12

3.2.1

Functional requirements ............................................................................................12

3.2.2

ROV classification......................................................................................................13

3.2.3

ROV stabilisation methods ........................................................................................13

3.3

INTERVENTION BY ROT .....................................................................................................16

3.4

LAUNCHING AND RECOVERY CONDITIONS ...........................................................................17

3.5

ROV CREW ......................................................................................................................17

3.6

OPERATION DOCUMENTATION ............................................................................................18

DEEPWATER ROV REVIEW ...................................................................................... 19 4.1

GENERAL ..........................................................................................................................19

4.2

ROV VEHICLE SYSTEM ......................................................................................................20

4.2.1

Vehicle structure ........................................................................................................21

4.2.2

Hydraulic power and propulsion ................................................................................22

4.2.3

Observation equipment..............................................................................................22

4.2.4

Navigation aid equipment ..........................................................................................23

4.2.5

Cabling systems.........................................................................................................24

4.2.6

Manipulator arm.........................................................................................................24

4.3

CONTROL SYSTEM.............................................................................................................26

4.4

LAUNCHING AND RECOVERY SYSTEM (LARS) ...................................................................27

4.5

TETHER MANAGEMENT SYSTEM (TMS) .............................................................................31

4.6

OBSERVATION ROV..........................................................................................................34

4.7

DRILLING ROV .................................................................................................................35

4.8

W ORKING ROV ................................................................................................................38

4.9

SURVEY ROV ...................................................................................................................40


DEEPWATER ROV AND TOOLS

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5

6


REMOTELY OPERATED TOOLS............................................................................... 41 5.1

GENERAL ..........................................................................................................................41

5.2

COMPONENT CHANGE-OUT TOOLS ....................................................................................41

5.3

PULL-IN AND CONNECTION TOOLS ......................................................................................42

ROV TOOLS ............................................................................................................... 44 6.1

GENERAL ..........................................................................................................................44

6.2

TOOL HANDLING AND IMPLEMENTATION ..............................................................................44

6.3

HYDRAULIC CONTROL INTERVENTION TOOLS (HOT STABS) ..................................................46

6.4

ROTARY TORQUE TOOLS ...................................................................................................47

6.5

LINEAR VALVE OVERRIDE TOOLS ........................................................................................49

6.6

DREDGE / JET PUMP SYSTEM .............................................................................................50

6.7

HYDRAULIC CABLE CUTTER................................................................................................51

6.8

FLOWLINE HUB CLEANING TOOL .........................................................................................51

6.9

SEAL REPLACEMENT TOOL.................................................................................................52

6.10 HYDRO-ACOUSTIC MEASUREMENT TOOL ............................................................................53 6.11 TAUT WIRE METROLOGY....................................................................................................54 6.12 ROV-MOUNTED PULL-IN AND CONNECTION TOOL ...............................................................56

ANNEX 1: DEEPWATER ROV........................................................................................... 57 ANNEX 2: ROV CONTRACTORS AND MANUFACTURERS ............................................ 60



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1

INTRODUCTION

1.1

Scope

Field development in deep waters typically involves the use of a floating production support in combination with a flowline network, subsea wellheads and manifolds. Such a development scheme results in numerous subsea intervention tasks that are out of the reach of the direct human intervention, thus putting demands on Remotely Operated Vehicle (ROV) role and reliability to a high level. ROV's were introduced offshore in the early 80's, as an observation and safety means of divers during their underwater interventions. With the acceptance of these new tools by the diving personnel, these remotely operated robots were further equipped with arms (i.e. manipulators) to perform more meaningful works than just observation tasks. At the same period deeper water development at 300 - 500 meters were being contemplated (mainly in the North Sea and in Brazil) as at that time exploration drilling was already deeper, and it is the drilling industry who has provided the ROV industry with the unique opportunity for further development. The incentives were twofold (1) ROV's are more cost effective than manned intervention (e.g. saturation diving systems, submarines, one-atmosphere bells) (2) safer operation as humans were not required in the hostile underwater environment. With commercial diving limited by water depths (e.g. 180 - 250 meters in North Sea and around 350 meters in Brazil), the ROV ability to work at extreme depths make it an essential tool for the offshore deepwater exploration and production. ROV's are the "eyes and the arms" of those who have remained in "surface". Today there are ROV readily available for 3000m water depth from all main ROV Contractors (e.g. CSO, SCS, Oceaneering, Sonsub, etc), and up to 6000m water depth (i.e. Ifremer). This document will review the current state of art in ROV's technology, its capabilities and the requirement for deepwater operations such as: •

route and seabed surveys

•

drilling supports

•

subsea interventions on subsea structures

•

Inspections, maintenance and repairs.

ROV subsea intervention effectiveness lay firstly with the adopted intervention philosophy, as further depicted in enclosed chapter 3, follows by the evaluation of the impacts on the Subsea Production System (SPS) design and ROV surface support vessel interface requirements (see chapter 2). Chapter 4 is dedicated to the general description of ROV system and the main technical characteristics for different ROV vehicles (i.e. Drilling ROV, Construction ROV, Survey ROV). Once the subsea tasks to be performed have been identified, the next phase is to establish the intervention method. There are two primary methods of remote intervention on subsea production systems, intervention by remotely operated tools (see chapter 5 – ROT) and intervention by tools mounted onto the ROV vehicle as further detailed in chapter 6, ROV Tools. The technical characteristics of the available deepwater ROVs and the list and addresses of the main ROV Contractors and Manufacturers provided in the annexes, will conclude this document. Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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1.2


Regulation, codes, standards & specifications

ISO-13628 (under preparation): • Part 8: Design and operation of ROV interfaces on subsea production equipment • Part 9: ROT intervention systems IMCA R 004: Guidance Note on the safe and efficient operation of Remote Operated Vehicles (AODC 051 previously) OLF-040: Recommended guides lines for ROV services

1.3


AODC:

Association of Offshore Diving Contractors

CCO:

Component Change-Out tool

FPS:

Floating Production System

HPU:


HPR:

Hydroacoustic Position Reference System

ICM:

Insert choke Module

IMR:

Inspection, Maintenance and Repair

LARS

Launch and Recovery System

MFM:

Multi-phase Flow Meter

MQC:

Multi Quick Connect

MTBF:

Mean Time Between Failures

OLF:

Oljeindustriens Landsforening (the Norwegian oil industry association)

OBSROV:

Observation ROV

PLEM:

Pipeline End Manifold

RCIU:

Retrievable Chemical Injection Unit

ROV:

Remotely Operated Vehicle

ROT:

Remotely Operated Tool

SCM:


Spread:

a complete system encompassing all equipment, spares, consumables and dedicated personnel

SPS:

Subsea Production System

SCSSV:

Surface Controlled Subsurface Safety Valve

TDU:

Tool Deployment Unit

TMS:

Tether Management System

WROV:

Working ROV



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1.4


References

This study is based on the following sources: • ROV Vendors / Manufacturer published technical data. • In house technical data from the ROV subsea contractors. • In house past experience in remotely operated subsea tasks. • Deepwater field development reference book “Tie-in Methods”.

1.5

Acknowledgements

We wish to thank the ROV manufacturers and subsea contractors for the provision with courtesy of technical information and photographs of their products.



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2


2.1

General

A deepwater ROV system is basically composed of the following sub-systems: •

launching and recovery system (LARS) with umbilical winch

•

propulsion system

•

camera system

•

lighting system

•

navigation system (sonar)

•

manipulator system

•

ROV tool system

Two sorts of ROV interfaces must be considered: •

interface between the ROV vehicle, tools and SPS (Subsea Production Systems)

•

interface between the ROV deck equipment and the surface support vessel

The surface support vessel can be either: •

a dedicated support vessel (e.g. ROV survey activities, subsea interventions)

•

a drilling support rig, DP vessel, semi-submersible, etc.

•

a Floating Production System

Defining the ROV operated systems, and hence evaluating the interface impacts on the SPS design and support vessel deck layout, requires also to precisely evaluate the subsea tasks to be performed. Such intervention philosophy and the functional requirements must be defined and the external environmental conditions criteria acting on it. Industry standard interfaces have been established for ROV intervention, to maximise the potential use of standard equipment and design principles. In general such ROV interface requirements and implementation lay mainly with the ROV Contractors. The purpose of standard ROV interfaces is to re-use intervention tooling in the interests of minimizing life cycle costs and to increase the use of proven interface tooling.



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2.2


Interface with subsea structures

The definition of the interfaces between the ROV and subsea production systems (SPS) mainly addressed the following topics: •

accessibility for ROV and tooling

•

interfaces between ROV tools and SPS (e.g. ROV panel)

•

ROV stabilisation method (e.g. docking system)

•

loads induced by subsea tasks (e.g. pulling, torque reaction forces)

•

required guiding devices (e.g. helical entry guide post)

•

required visual aids (e.g. marking, color coding)

The ROV interfaces are generally located on the SPS in a manner that allows accessibility to the ROV, tools (i.e. manipulator, TDU or tool skid mode) and ROT. This means that the overall dimensions of the ROV and its tooling package (or the ROT) must be taken into account in addition to the required space to manoeuvre. In the design of the SPS interfaces, attention must be paid to the environmental conditions as significant current could tremendously complicate the pilot task. Component Change-Out tool landing units ROV panel

Tool Deployment

SPS

Unit (TDU)

ROV

Figure 2.1 - "Illustration of some interfaces between ROV and SPS" Interface between SPS and ROV are generally performed by ROV panel. It includes the various interfaces for rotary torque tools and linear pushing tools for valve actuation, provides inboard hubs of MQC or female receptacle for hydraulic intervention tool, etc. (see enclosed chapter 6: "ROV tools"). It also provides docking points (if TDU method is used) or grasping bars for ROV stabilisation (see chapter 3.2.3 for further details on the stabilisation methods).



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Valve state markers

Female MQC "T" bar

Figure 2.2 - "ROV panel" SPS may be also equipped with landing units for landing and locking of ROT (e.g. Component Change-out tool) if required. The functions of these units are to perform the final alignment, to provide soft landing, to lock the ROT during the operation if required and to support tool weight and eventual additional loads. The SPS and the interface items must be able to support various loads induced by: •

ROV stabilisation (environmental loads acting on ROV, tooling package and umbilical tether must be considered)

•

tooling engagement

•

subsea works to be performed (i.e. tool reaction loads)

•

eventual collisions

An adequate colour and marking system of SPS must be implemented to allow easy identification of: •

structures (for global navigation)

•

key subsea equipment (e.g. control pods, latching items)

•

inspection area

•

intervention interfaces (e.g. ROV panel)

•

status of each equipment (e.g. open or close position for valves)

The colours generally used are yellow (most visible colour through a subsea camera), white and orange in combination with black and grey. Character sizing depends on the distance they should be read, depending on their role (i.e. primary identifier for system location or secondary markers, such as those on ROV panels). They can be from 5cm to 50cm height. Prevention of marine growth and cleaning (e.g. jetting, brush) shall be provided for markers having operational functions for the field life duration.



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2.3


Interfaces with support vessel

The interfaces between the surface support vessel and the ROV system mainly concern (1) the deck layout (i.e. space required by the deck equipment of the ROV and associated equipment) and (2) the required facilities (e.g. power, communication, etc.) for further mobilisation activities onboard the surface support vessel. As a minimum, the ROV deck equipment includes: • launching and recovery system (LARS), handling frame or crane, electrohydraulic umbilical winch complete with drum, cables and umbilical capable of operations at the required water depths • ROV control cabin fully equipped (i.e. monitor recorder with hard copy print out off the screen), air conditioned and pressurised as Zone 2, A.60 fire rated • video display to be located in the support vessel main control room (e.g. DP control, drill cabin) • direct communication and telephone links between the ROV control cabin and the 'DP' control room • workshop / maintenance cabin • all required spare parts for above ROV system ROV's Subsea Contractor must provide a general arrangement on deck of its equipment/system and the required facilities / connections interfacing with the support vessel. The surface support vessel must provide a safe working platform for the subsea activities to be performed by ROVs and ROTs. This implies that both support vessel and LARS shall be related for effective operations at the defined environmental conditions or sea state (see section 3.4 Launching and recovery conditions).



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3

INTERVENTION PHILOSOPHY AND FUNCTIONAL REQUIREMENT

3.1

General

Working effectively in deep water demands more efficient subsea operations which start with the ROV equipment capabilities, but lays mainly with the ROV personnel / operator skill and training, and with the ROV Subsea Contractor culture and attitude for services and performance. With deepwater applications, reliability of the ROV system becomes much more a vital factor for operation success and cost effectiveness. Priority is being given to increase the endurance of equipment so that the vehicle does not have to be brought back on deck for routine maintenance, as the round trip from/to 2000 m can take more than 4 hours. Although such deployment time could be reduced with the use of traction winch capable of 100 m/minute launch & recovery speed. Typical ROV breakdowns are related to the main and tether umbilical, electronic pods and electrical connectors following a water ingress or condensation effect due to a much colder water at seabed (e.g. 4°C, -2°C). Today an ROV working rate of up to 98% is achievable, when the ROV design is based on the "degraded mode of operation" philosophy. This implies that high risk ROV sub-systems are provided with built-in backup systems in the event of failures of the primary system. In most cases, the ROV will be able to continue the mission but at a reduced performance. The most well known high risk sub-systems which are to be provided in dual mode are: dual HPU, dual motors, dual depth sensors, dual navigation compasses, multiple cameras, dual sevenfunction manipulators, multiple fibre optic data transmission, etc. The establishment of an intervention philosophy at an early stage of ROV system design for particular application allows defining the required types of ROV, the eventual ROTs, the associated equipment (i.e. ROV tools) and then to manage the interfaces (i.e. with SPS, deck layout, etc.). Such intervention philosophy must be defined as early as possible and should address: •

the various tasks to be carried out (survey, drill support, SPS installation, IMR)

•

the type of support vessel (drilling rig, construction vessel)

•

the intervention methods (ROV, ROT)

•

the required types of tools (torque tools, hot-stab, etc.)

•

operators skill and eventual specific training

•

ROV stabilisation method (e.g. docking panel, working platform)

•

SPS accessibility requirements (versus ROV dimensions, manipulator envelope)

Remote subsea operation can be conducted either by ROV or ROT (with ROV used for backup function).



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Typical intervention tasks include: •

visual inspection and monitoring

•

cable cutting

•

measurements (metrology)

•

component installation and replacement (e.g. transponders, modules)

•

template / wellhead workover (e.g. valve operation and emergency override, valve maintenance and testing, etc.)

•

umbilical and flowline installation (i.e. pull-in and connection)

•

pipeline burial

•

etc.

The functional requirements are performance oriented and should define the minimum criteria which must be satisfied in order to meet with stated objectives (e.g. to provide reliable ROV support to ensure cost effective and safe operation): •

list of subsea tasks to be performed

•

ROV launch and recovery limitations versus weather window (sea state definition)

•

available ROTs and/or ROV tooling (e.g. generally from the SPS manufacturer) to be interfaced to the ROV systems

•

ROV availability or working rate

•

contingency plan in case of ROV failures (e.g. availability of spare parts, components, vehicle, umbilical, etc.)

•

continuous improvement plan based on experience feed-back (for both ROV operators and Contractors)

•

etc.

3.2

Intervention by ROV

3.2.1

Functional requirements

ROV is a compliant system that allows to perform various subsea tasks such as those quoted in previous section. Deepwater ROV design shall provide adequate equipment / tooling and the capacity to interface with the SPS design, with sufficient power (i.e. for tool implementation and propulsion adapted to the subsea conditions), depth capacity, etc. Three main ROV configurations can be adopted to perform these subsea tasks : •

ROV fitted with manipulators

•

ROV equipped with Tool Deployment Unit (TDU)

•

ROV with toolskids or handling frame

The ROV spread shall be designed, based on the modular concept for ease of transportation, handling, mobilisation and transfer onto alternative support vessel.



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3.2.2


ROV classification

ROV are typically grouped into about five categories, classified by role and/or size. AODC 051 gives the following classification: •

Class I:

Observation ROV

•

Class II:

Light-work or observation ROV with payload option

•

Class III:

Work ROV

•

Class IV:

Towed or bottom crawling vehicles

•

Class V:

Prototype or development vehicles

Observation ROV are employed for visual inspection / monitoring and diver assistance. These systems are typically fitted with light sensors, probes and a simple grabber but carry little or no payload. Class II ROV is used for tasks ranging from inspection, observation and assistance during drilling operations and light subsea tasks (e.g. 150-200 kg). They can carry one or two cameras, sonar and a single manipulator arm; they are able to carry light payload tasks. Work ROVs are employed for various tasks such as drill support, construction and repair tasks, platform cleaning, subsea tool deployment and operations (e.g. up to 500 kg). They feature higher hydraulic power and payload capacity, more sensor channels and are generally fitted with either a grabber and a seven-function manipulator arm (e.g. for drill support) or two seven-function manipulator arms (e.g. for construction tasks). The WROV spread shall be based on the same design as the drilling support ROV, and as much as possible using the same components, control systems, equipment, etc for the purpose of ROV's pilot / technician training, familiarisation and maintenance aspects (e.g. same spare parts). Towed or bottom crawling are typically purpose built to a particular intervention task (e.g. subsea trenching or pipeline repair). Each ROV must accommodate a wide variety of tooling, work equipment and sensor systems. Standardisation efforts on the equipment are performed, leading in particular to the ISO recommendations.

3.2.3

ROV stabilisation methods

The intervention philosophy shall address the stabilisation method employed by the ROV in order to be able to define the interfaces with the subsea structure and the ROV equipment. The stabilisation can be achieved by means of the following: •

suction cups

•

grabber

•

docking device

•

working platform



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Suction cups fixed on the end of an arm and activated by the ROV allow to anchor it by suction effect when in contact with the structure. This system allows to perform some manipulative operations, such as cleaning, valve activation or inspection, but it requires flat and relatively clean surface near the work area. This stabilisation method is adopted for subsea intervention tasks on subsea structures which have not been prepared for ROV operations at the design stage.

Figure 3.1 - "Suction cup"



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ROV can grasp bars on the structure by means of a manipulator / grabber arm with parallel or pincer jaw. Adequate standard bars must be fitted onto the subsea structure, which shall resist the loads applied by the ROV (ISO recommends to design grasping intervention interfaces to resist a force of about 225kg applied from any direction). Docking is generally used in combination with TDU (see chapter 6), but it can also be used during manipulator operations. It is convenient when effort transmission to the working interface must be avoided (e.g. during operation involving hot stabs) or when heavy loads are handled (e.g. stab plate connection). Docking provides stable and accurate positioning of the ROV; it is performed by stabbing one or two docking probes in docking receptacle(s). The docking probe is an hydraulically operated device with locking dogs at its extremity, as depicted on figure 3.2. Docking receptacle

ROV panel

Docking probe

Docking face (SPS/ROV panel) Docking probe

ROV tooling

Locking dogs

TDU

Figure 3.2 - "Docking principle" A working platform can be used in replacement or in combination with one of the previous stabilisation methods. It can be composed of bars or gratings.



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3.3


Intervention by ROT

Remotely Operated Tools (ROT) are generally used to perform the replacement or installation of SPS components, flowlines and umbilical connection (see figure 3.3). They are preferred to free-flying ROV intervention mode when high lifting or pulling capacities are required. ROTs are lowered by means of lift wires and powered by a surface umbilical with either dedicated thrusters or ROV assistance for lateral guidance. If necessary, ROV are used to activate backup functions.

Figure 3.3 - "sketch of ROT intervention system"



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3.4


Launching and recovery conditions

The ROV vehicle is generally launched over-the-side (sometimes through a dedicated moonpool) and requires a purpose built Launch & Recovery System (LARS) to control the pendulum movements on deck and until it extends through the sea splash-zone. Because it extends the weather window and provides longer duration dives, the LARS is now regarded by many as the next major step in deepwater ROV development, with the umbilical being the most critical item for further improvement. Such handling system shall be designed, built and operated to suit the conditions in which it is to perform. Today most LARS are designed to meet with sea state 6: •

significant wave height Hs=4m to 4.5m

•

wave peak period Tp=8s

This implies that ROV operations should not be subject to weather downtime in milder areas (than North Sea) such as West of Africa, Brazil or Gulf of Mexico (excluding during hurricane period), and providing that such diving operations are performed from a suitable surface support vessel.

3.5

ROV crew

Efficiency of the ROV crew is a major factor of subsea operation success. Deepwater ROV workforce is responsible for: •

the ROV maintenance

•

the correct implementation of the operational procedures

•

the adequate and accurate ROV manipulation

•

experience feed back for further improvement of equipment, procedures, etc.

The personnel shall be qualified and sufficiently experienced. Deepwater ROV crew typically consists of the following, during 12 hour shifts in 24 hour operations: •

one supervisor, whose role is to prepare the operations and to interface with the support vessel operation superintendent

•

one senior pilot / technician

•

one pilot, helping the senior pilot by manipulating the arm, the TMS, the LARS, etc.

The above 3 men crew are generally sufficient during most of the drilling campaign, however 2 additional pilot/technician will be required for a continuous 24 hour coverage during the high activity periods such as re-entries, well completions. For subsea construction activities (e.g. flowline tie-ins) a much higher workload will be required from the WROV spreads, in general a minimum of 2 WROVs and 12 men crew (i.e. 6 men crew/12 hrs shift) are needed. IMCA are putting together a competence scheme for ROV personnel, which hopefully carry City & Guilds accreditation. This will involve the keeping of log books, recording of vehicles and tools used.



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3.6


Operation documentation

Two media are used to consign and record all the ROV activities: •

video tape, which continuously records ROV activities.

•

dive log, which reports ROV tasks, also covering the launch / recovery times and surface activities.

Following the latest computer technology improvements, some subsea contractors now offer to use digital video interface, converting all video received from the ROV into a digital format and hence allowing a broad range of utilisation and modification (image insertion in the reports, addition of graphs to the images, etc). The ROV report from the subsea operation includes as minimum the ROV procedures, the dive log and a short video version of the operation.



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4

DEEPWATER ROV REVIEW

4.1

General

Deepwater ROV systems are composed of the following main items: •

vehicle

•

tether management system (TMS)

•

umbilical and winch

•

launching and recovery system (LARS) and associated equipment

•

telemetry and control system

•

fibre optic system

•

control and maintenance cabins

•

power generator

•

spares

Additional equipment and tools are then added, depending on the subsea tasks to be performed and the ROV intervention mode (e.g. with TDU, tool skid, etc.). Some ROVs feature up to 200 hp, but in general 100 hp are sufficient for most purposes and separated in two units of 2 x 50 hp for redundancy and degraded operation philosophy. For deeper waters than those currently envisaged (i.e. more than 1500 m), most ROV manufacturers will just uprate an existing model, which is largely a case of ensuring that the electronics are adequately housed, the vehicle's buoyancy, lights and cameras are designed for the planned water depths. The following sections further describe the ROV vehicle, control system, LARS and TMS as common part of all the (deepwater) ROV systems. The different types of deepwater ROVs are then depicted.



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4.2


ROV vehicle system

The ROV vehicle is composed of an open frame, fitted with buoyancy modules, supporting the hereunder-detailed minimum equipment and eventually some additional tooling (e.g. TDU, services skid, etc.): •

HPU and propulsion system

•

observation equipment

•

navigation aid equipment

•

cabling system

•

manipulator arms Thrusters

Umbilical tether

Flotation modules Pan and tilt camera unit Grabber

Electric/electronic 1 atm. pods HPU

Tooling HPU manifold

7F Manipulator

Figure 4.1 - "ROV main components"



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4.2.1


Vehicle structure

The ROV vehicle structure is a welded open frame, made generally from aluminium alloy with stainless steel fixtures and designed to: •

carry all the ROV sub-systems

•

support additional payload hung under the frame (e.g. tool skid)

•

allow easy access to the sub-systems for control and maintenance

•

carry additional tools (e.g. in TDU intervention mode)

The open configuration keeps clear waterways for thrusters water flow. The frame is protected against corrosion (e.g. sandblasting) and fitted with anodes for corrosion control.

Flotation modules

Grabber (5F)

ROV framework

Thrusters

Figure 4.2 - "Slingsby's MRV deepwater ROV" Deepwater ROV vehicles are equipped with syntactic foam flotation modules, which provide adequate trim and allow the ROV to be slightly buoyant or nearly neutral. The syntactic foam is preferred to materials such as polyurethane or copolymer foams due to its deepwater pressure resistance capacity. Syntactic foam is composed of hollow glass microspheres (typical diameter of about 100 – 150 microns) dispersed within a base polymer; hollow macrospheres (typical diameter of 5cm) can be added to reduce the foam density. A 2500m water depth rated composite syntactic foam typically has a density between 450 – 500 kg/m3.



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4.2.2


Hydraulic power and propulsion

The ROV vehicle is generally powered by two hydraulic power units (e.g. 2 x 50 hp), each being able, if required, to independently operate the system at reduced power hence providing more reliability. Each HPU is composed of the following main items: •

electrical motor (e.g. 50 hp, three-phases, 60Hz, 2300 VAC motor)

•

hydraulic pump (e.g. 50 hp)

•

coupler, joining motor and pump, contained in an oil filled, pressure compensated housing to avoid water ingress

•

pressure compensated reservoir, feeding the pump

The hydraulic power is distributed by means of valve manifolds to the various ROV subsystems, which are mainly: •

thrusters

•

manipulators

•

camera pan and tilt unit

•

tools

ROV is typically equipped with 6 – 8 fixed thrusters allowing manoeuvres in all directions. Thrusters are controlled by servo valves, which supply them with hydraulic power. Each of them is able to provide typically about 250 – 300 kg of thrust.

4.2.3

Observation equipment

Camera function is to provide visual support to the ROV pilots to manoeuvre the vehicle and perform the various subsea tasks. Two types of cameras are generally fitted on ROV: •

SIT (Silicon Intensified Target) low light camera

•

CCD (Charge Coupled Device) camera

SIT camera is primarily used by the ROV pilot during the vehicle's manoeuvres. It provides a wide angle of vision and the best viewing in poor visibility conditions, allowing discerning the eventual obstacles (e.g. cable or rope). The low light viewing capabilities of the SIT camera allow locating a target from a greater distance than a CCD camera. CCD camera is generally used for close in work or inspection tasks. It can be for example mounted on a manipulator to view tooling functions. The cameras can be located: •

on a fix location on the ROV (still camera) to be used as a reference camera for ROV manoeuvres.

•

on a pan and tilt unit, allowing to orientate the cameras for observation, reading of gauges, etc.

•

on manipulator or tool frame as tool operation support cameras



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Figure 4.3 - "Cameras and lights on a pan and tilt unit" A camera positioned at the rear of the vehicle allows not only to perform manoeuvres but also to check the tether position. Another camera can also be fitted on the TMS to allow viewing of the tether winch, various gauges located on TMS (e.g. hydraulic gauges of HPU, which provides power to the tether drum) and the whole vehicle deployment and recovery process. A sufficient lighting system must be fitted on the ROV to provide the required video coverage. About four to five 250Watt lights (e.g. dry quartz halogen lamp) are typically mounted on the ROV vehicle, on the pan and tilt unit, at the front and rear of the ROV to provide the uniform, balanced lighting required for video coverage.

4.2.4

Navigation aid equipment

The ROV must be equipped with heading, depth, altitude, and pitch and roll sensors to assist the pilot during manoeuvres. The gyrocompass heading sensor provides the pilot navigational aid to assist in tasks requiring directional orientation (e.g. locating the work site). Depth sensor or altimeter can be used to hold vehicle position in the mid-water column while performing an operation, but altimeter is generally more accurate and stable due to a shorter range (i.e. typically 50m). Inclinometers help the pilot or the autopilot functions in controlling the vehicle position, roll, pitch. Roll sensors are particularly useful when docking or mating operations are performed or to work above a slope bottom. Use of sonar allows spatial orientation and easy location of targets (e.g. SPS, pipelay) during operation. Generally, as the ROV operates in a predetermined area, a medium to short range sonar is sufficient, allowing to track target in relatively close range (i.e. up to 100 - 200m) and to obtain high resolution images. ROV are positioned by means of hydro-acoustic system; the short baseline (SBL) system measures a range and direction from the surface support vessel mounted hydro-phones (or transceivers) to a mini-beacon mounted on the ROV. Latest development on super-short or ultra-short baselines (SSBL, USBL) for deep water survey used only one hull mounted hydroRev. 0 30/09/2000 DGEP/SCR/ED/TA


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phone/transceiver and one subsea beacon (transponder) to establish a 3D position of the ROV. In contrast, the long baseline (LBL) measures position with a ‘range range’ technique which relies on transponders at known point on seafloor, or in an array (see section 6.10). The LBL provides a higher accuracy (than the SBL system) and is used mainly for subsea positioning and metrology. 4.2.5

Cabling systems

Connectors are generally used on external components to facilitate control and maintenance. All the connectors are pressure balanced to avoid water ingress by means of an oil-filled, pressure compensated tubing. A junction box is used to centralise the main connections, minimise the risk of leaking and ease the maintenance. 4.2.6

Manipulator arm

Deepwater ROVs are typically equipped with either one seven-function manipulator arm and one five-functions grabber, or two seven-function manipulator arms (i.e. construction tasks).

7XF Shingsby TA40 Storm 2X7F Schilling CONAN

7XF Slingsby HYDRUS Figure 4.4 - "Manipulator arms" Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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The state of art is a 'six degrees of freedom' plus claw, master / slave system for underwater applications. Higher dexterity is achieved by the use of rotary-vane actuators at the joints, thereby eliminating the envelope restrictions imposed by hydraulic rams (i.e. Slingsby HYDRUS). The typical characteristics of five-function and seven-function manipulators are hereafter described: Five-functions arm/grabber typical characteristics: •

linear working area:

1 – 1.5m

•

lifting force fully extended:

50 kg (200 kg retracted)

•

rotation torque at the wrist:

75 - 200Nm

•

wrist rotation:

340°

Seven-functions manipulator arm typical characteristics: •

linear working area:

1.3 – 2m

•

lifting force fully extended:

50 kg (210 kg retracted)

•

rotation torque at the wrist:

50 - 150Nm

•

wrist rotation:

continuous 360°

Side elevation (m)

Plan elevation (m)

Figure 4.5 - " Typical seven-function manipulator operational envelope" The manipulator arms may be fitted with miniature cameras, installed on manipulator ‘wrest’ to further improve the operator views.



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4.3


Control system

The control system is housed in a control cabin located on the surface support vessel deck. A maintenance cabin is also part of the on-deck ROV system, providing enclosed atmosphere, to store spares and performs maintenance operations. Both cabins can be airconditioned, pressurised as Zone 2 and A.60 fire rated if required (i.e. drilling rigs). The control system is typically composed of: •

a pilot's console, with all joysticks, switches, trackball and computer graphics user-interface components.

•

a navigator's console, including video tape recorders, a sonar processor and monitors.

Pilot's console Sonar processor

Video tape recorders

Navigator's console Figure 4.6 - "Control system" A video overlay on the pilot's monitor allows to display one or a combination of the following data: date / time, depth / depth history, heading and auto heading set point, altitude, pitch and roll, hydraulic data (i.e. pressure, temperature, fluid level), motor current and voltage status, thrusters status, alarms, etc. Direct communication and telephone links between the ROV control cabin and the "DP" control room must be provided to allow full subsea intervention co-ordination. The electrical power distribution is generally enclosed in the control cabin (but separated from the control room by wall for safety reasons), providing power to the ROV system HPU motors, electronic hardware on the ROV and the control and maintenance cabins. The telemetry and control system is the ‘heart’ of the ROV technology, it provides high speed serial communications, utilising topside computer, and a bottomside microchip (e.g. Intel Pentium) control system in the ROV vehicle/cage. Through the use of standard industrial computer components and ‘custom’ designed software, the control system is flexible, reliable and easily maintained. The control logic for various vehicle functions, any added specialized tooling could be updated or reprogrammed to suit subsea tasks specific needs and applications.



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4.4


Launching and Recovery System (LARS)

The functions of a LARS are (1) to perform the overboarding of the ROV and its TMS, (2) to avoid any critical pendulum motions which would conduct to detrimental clashes between ROV and floater hull and (3) to lower and recover the vehicle / TMS assembly through the splash zones. The launching and recovery system consists of following major components: •

handling frame

•

umbilical winch

•

on-deck hydraulic power unit (HPU)

A-frame Umbilical winch

Docking head

ROV TMS (side entry cage)

Figure 4.7 - "A-frame type, moonpool based LARS" The handling frame can be based on either an A-frame (see figure 4.7) or a crane (knuckleboom or telescopic boom, see figure 4.8). Its primary function is to perform the overboarding of the TMS, which is hanged on the docking head and supports the ROV, and to position both TMS and ROV at the sea water level as far as possible of the floater hull (i.e. typically an overboarding reach of about 5m) in order to avoid contacts due to environmental loads and pendulum movement. The handling frame shall withstand the weight of the TMS, the ROV, plus its maximum payload (corresponding to an eventual added tool package); it shall be able to perform its task in severe conditions.



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Umbilical Docking head TMS (Top-hat design)

Figure 4.8 - " knuckle-boom type LARS" The umbilical winch can be fitted with active heave compensation, thus ensuring safer and simpler docking of the ROV in rough weather conditions. The umbilical winch determines the deployment / recovery speed of the ROV, which is typically about 30m/min. Speed is an important characteristic of a LARS for deepwater applications as launching and recovery times increased with depth, thus resulting in enormous expenditure. For deepwater and ultradeepwater operations, the umbilical winch should provide at least a deployment / recovery speed of 50m/min.

1

2

Position: resting

Position: overboarding 4

3

Position: working extreme

Position: working close

Figure 4.9 - " knuckle-boom type LARS launching sequences"



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Mobil, who was particularly concerned with this problem in the West of Shetlands with the drilling semi-submersible "Jack Bates", awarded Subsea the design and fabrication of a ROV system deepwater / harsh environment. Subsea developed the "Clansman" ROV system, including not only a deepwater ROV (rated to 2000m) but also a heavy weather LARS. The Clansman LARS is based on the use of four guide wires and a cursor frame which guide the ROV cage from the main deck down to submerged pontoon level of the semi. It allows launching and recovery of the ROV in sea state 8 (i.e. significant waves of up to 10m) and its high speed umbilical winch is able to lower the ROV at a maximum speed of about 140m/min.

Figure 4.10 - " Clansman system" The umbilical is usually the weak element of a ROV system, particularly for deepwater applications due to the umbilical increasing length and weight. The main lift umbilical experiences maximum working loads during launching and recovery of the ROV at the splash zone, with TMS and vehicle freely suspended in water. A failure of a winch or an umbilical statistically results in the longest ROV system downtime period. Efforts are made by ROV/umbilical manufacturers to: •

minimise the weight of the umbilical while maximising its capability

•

standardise umbilical in order to facilitate the storage of spare umbilical



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Deepwater main lift umbilical are typically composed of power conductors and fibre optics internally installed in helical arrangement to reduce load stress (fibre optics can also be surrounded by a protective gel to minimise friction with other components). The umbilical allows the transmission of power, data, telemetry and video between the TMS and the surface. The umbilical electrical components should be isolated and checked for possible interference between power and data/video transmission. The use of fibre optics can improve the umbilical size and weight; this allows to reduce the drag loads (i.e. the current induce offset) and to minimise the size (and the cost) of the LARS. But fibre optics forbid any repair as it can not be welded offshore. Standardisation is hence important to allow an optimisation of spare umbilical.



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4.5


Tether Management System (TMS)

In general ROV's operating deeper than 500 m need a tether management system to remove the effect of current on the main umbilical, and to improve ROV manoeuvrability. The TMS functions are (1) to latch the ROV during the launching and recovery phases and (2) to manage the tether length while the vehicle performs the subsea tasks. The ROV is unlatch from the TMS and leave it when reaching the desired water depth and then can manoeuvre in any direction up to the working length of the tether. The tether umbilical length is normally 200 m with trend to increase it up to 600 m, with the use of fibre optical which provide a smaller umbilical as narrow as 27 mm OD. TMS allows decoupling of the vessel motions, surface effects and drag loads on the umbilical through the water column. The ROV power can hence be fully used to perform the subsea tasks as the vehicle pulling charge is minimised (the ROV is only retained by the tether drags, which are quite inferior to those acting on the total umbilical length). Current loads acting on the main lift umbilical and the TMS tend to push it far away from the working area. The TMS weight, this is particularly true when high current are expected, is useful to adequately position the ROV. Some TMS (e.g. the cage of the Hydra Magnum ROV) are equipped with thrusters to assist in the positioning. TMS is equipped with HPU (i.e. motor, coupler, hydraulic pump, plumbing, etc.), generally similar to the ROV equipment for maintenance purposes, and valves to provide with hydraulic power and to control the tether winch (and the eventual TMS propulsion system). Cameras and lights are also fitted for viewing of hydraulic gauges, tether winch and the vehicle deployment and recovery process. All power and control for the ROV vehicle, after passing through the main lift umbilical, are provided by the tether umbilical.



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Today, two types of TMS are available on the market: •

side entry cage

•

"top-hat" TMS

Figure 4.11 - "Side entry cage"

Figure 4.12 - "Top-hat TMS"

The typical main characteristics of both systems for deepwater applications are as follows: Side entry cage

"Top-hat" TMS

•

Length:

3.2m

•

Diameter:

1.9m

•

Width:

2m

•

Height:

1.9m

•

Height:

3.5m

•

Weight in air: 1.7ton

•

Weight in air: 2ton

Both cage and top-hat are equally used by the manufacturers / contractors as each of the two systems has the opposite advantages and drawbacks. The two main problems encountered with a "top-hat" designed TMS are: •

due to the top position of the TMS and the low submerged weight of the ROV, a turning moment is applied on the ROV-TMS combination when lowered into the water (i.e. the centre of gravity rises above the centre of buoyancy), thus applying large lateral loads on the umbilical termination.

•

It is relatively easy to pinch the tether when the ROV docks the TMS.



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A side entry cage has the inherent advantage of providing protection to the ROV during

Tether

Figure 4.13 - "Slingsby MRV's Top-hat TMS"

launching and recovery (useful in bad weather conditions to avoid direct clashes on the floater hull), but its main drawbacks is to be less versatile: the size of tools and work packages to be added on the ROV is limited by the cage dimensions.



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4.6


Observation ROV

Observation ROVs (OBSROVs) are rarely used during deepwater operations: because of the high duration of ROV launching and recovery operations, heavier ROV are often preferred as they are able to immediately perform more demanding subsea tasks. Nevertheless, class II observation ROV function in deep waters is mainly to perform inspection of the subsea equipment (i.e. SPS, risers, sealines), video monitoring (during tool manoeuvre and positioning) and light subsea works. Observation ROV can carry a wide range of light sensors and probes, plus a simple (i.e. from one to three-function arm) grabber, but it can not carry heavy loads.

Figure 4.14 - "Perry Tritech Viper observation and light work ROV"

The main characteristics of a typical deepwater class II observation ROV are as follows: •

dimensions:

2.2m x 0.9m x 1.2m (LxWxH)

•

total power:

50hp

•

weight in air:

850kg

•

depth rating:

2000m

•

speed:

3 knots forward 2 knots reverse 1.5 knots lateral 1.5 knots vertical

•

payload:

80kg

•

manipulator:

four-functions

The enclosed Annex 1 provides further technical characteristics of the main class II OBSROV for deepwater applications.



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4.7


Drilling ROV

The drilling ROV will generally provide the required assistance during: •

re-entries, drilling and well completion

•

X-mas tree installation

In particular, it must be suitable for performance of typical subsea tasks as follows: •

General observation ∗ observing spudding of well ∗ watching for fluid and cement returns to seabed ∗ observing and advising rig about guidance of bit or casing into well ∗ observing landing of equipment (e.g. guide base, BOP) at seabed ∗ observing and reporting currents

•

Quality control observations ∗ checking bulls-eye for inclination of guide base, BOP, etc. (+/-1deg) ∗ checking orientation of guide base (+/-5deg) ∗ checking elevation of conductor above seabed (+/-0.5m) ∗ checking position of subsea equipment relative to rig position (+/-0.5m) ∗ confirming position of connector latch indicators (+/-1cm) ∗ observation of wellhead seal surface (from distance of about 0.25m) ∗ observing pressure during function tests with ROV stabs (+/-0.5bar) ∗ observation of BOP alignment pin position (+/-1cm)

•

Manipulation tasks ∗ position beacons on seabed and/or on subsea equipment ∗ insert hydraulic stab onto BOP, tree, tubing spool and pressurise (e.g. 210bar) to function/pressure test with sea water ∗ install and remove environmental gasket onto/from wellhead ∗ actuate retaining rods on BOP connector to release ∗ cut hydraulic line ∗ clean (mechanical and hydraulic) external and internal wellhead housing (seal surface) ∗ manipulation of needle valves on BOP control panel ∗ connect/disconnect lift wires to/from subsea equipment ∗ remove small debris ∗ remove/clean cement and cuttings from guide base ∗ operate manual (ROV) gate valves ∗ override hydraulically actuated tree valves ∗ carry and install tree cap ∗ pressure control and methanol injection in tree cap ∗ connect/disconnect electrical subsea connections



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Figure 4.15 - "Oceaneering Magnum ROV" Drilling ROVs are class III deepwater ROV. The main characteristics of a typical deepwater drilling support ROV are as follows: •

dimensions:

2.5m x 1.5m x 1.6m (LxWxH)

•

total power:

100hp

•

weight in air:

2ton

•

depth rating:

2000m – 3000m

•

speed:

3 knots forward 2 knots lateral 2 knots vertical

•

payload:

50kg – 100kg

•

through frame lift:

1ton – 5ton

•

manipulator:

1 x seven-function manipulator arm 1 x five-function grabber

The deepwater ROV system as a minimum should be equipped as follows: •

scanning sonar with a range of 200-250 m and a 360° angle

•

two (2) manipulator arms, one 7 functions and one 5 functions

•

two (2) video cameras with at least one (1) being high resolution colour camera and both equipped with pan & tilt system and video recorder with functions to edit tapes, provide hard copies off the screen and to add a sound track (VHS system)

•

data transmission via fibre optic technology



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•


following instrumentation shall be connected to a surface display: ∗ automatic/manual heading and depth control, and be able to lock itself in all three (3) axis by means of its control system ∗ gyrocompass ∗ thermometer for water temperatures at seabed ∗ depth-meter ∗ HPR system

•

thruster propulsion system shall be sufficient for propelling and manoeuvring the vehicle in all directions at any depth and withstand currents up to 2 knots at seabed level

•

high pressure pump system, 3000 psi, with line and hot stab for BOP actuation

•

ROV tools : ∗ AX or VX ring tool ∗ hydraulic cable cutter ∗ hydraulic actuated wrench for 2" sockets

The drill support ROV, shall be able to be trimmed neutral buoyant (or slightly positive) when carrying special tools. The ROV shall be capable of a through frame lift of 500 kg (in air). The ROV hydraulic power packs shall have spare valves to be able to operate two functions bi-directional at an operating pressure of 210 bar (e.g. x-mas tree valves override operation).



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4.8


Working ROV

Deepwater working ROV (WROV) are used for installations or production supports, to perform subsea tasks such as: • • • • • • • • • •

all tasks as for drilling ROV (see section 4.7), plus landing, make-up, test, disconnect the SPS manifold pull-in and connection of flowlines and umbilicals install electrical and hydraulic flying leads between SPS hydraulic primary and secondary tool operations (e.g. manifold valves) operation of valves as primary or override functions water jetting and dredging deploy, install, make-up, test, disconnect, recover the X-mas tree mounted equipment (i.e. choke inserts, control modules, chemical injection, flow meter module) operation of other purpose designed ROV tooling etc.

Toolskid

Figure 4.16 - "SEL Slingsby MRV ROV (with toolskid)" The deepwater working ROV is a new generation of deep-water ROV specifically designed for construction support activities and out-fitted with a Tether Management System (TMS). Working ROVs are class III deepwater ROV. Typical characteristics are as follows (see Annex 1, which gives further technical characteristics of the main class III deepwater ROV in tabular form): • • • • •

dimensions: total power: weight in air: depth rating: speed:

3m x 1.6m x 1.7m (LxWxH) 100hp – 150hp 2ton – 3ton 2000m – 3000m 3 knots forward 2 knots lateral 2 knots vertical

• •

payload: through frame lift:


150kg – 300kg 1ton – 5ton DEEPWATER ROV AND TOOLS

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•

manipulator:

2 x seven-function manipulator arms

•

automatic functions:

auto heading, auto depth, auto altitude

Figure 4.17 - "Perry Tritech Triton XL ROV" The ROV system shall be capable of operation down to the required depth and as a minimum shall be equipped as follows : • scanning sonar with a range of 200-250 m and a 360° angle • two (2) 7 function manipulator arms with the following SPS requirement (see also chapter 4.2.6): ∗ reach of 1.3 m ∗ wrist function of continuous 360° rotation ∗ claw rotate torque of 75 Nm minimum ∗ lift capacity of 500 N at full extension and 1000 N in retracted position • as an alternative, computer assisted manipulators (based on latest technology for environment acquisition and load return forces) can be proposed for elementary & repetitive tasks such as valve operations, torque operations, etc, • two (2) video cameras with at least one (1) being a high resolution colour camera and both equipped with pan & tilt system and video recorder with functions to edit tapes and to add a sound track (super VHS system) • data transmission via fibre optic technology • following instrumentation shall be connected to a surface display: ∗ automatic/manual heading and depth control and be able to lock itself in all three (3) axis by means of its control system ∗ gyro-flux gate compass (to prevent from magnetic field subsea structure) ∗ thermometer for water temperatures at seabed ∗ depth-meter ∗ HPR system • thruster propulsion system shall be sufficient for propelling and manoeuvring the vehicle at any depth with current up to 2 knots at sea-bed level • multiplexing control capability allowing additional sensors and tools to be attached, with additional spare twisted pair to allow for additional direct control • high pressure pump system, 3000 psi, with line and hot stab for override functions on the SPS Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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• ROV tools : ∗ hydraulic cable cutter ∗ hydraulic actuated wrench for 2" sockets ∗ water jetting & dredging tools The working ROV, shall be able to be trimmed neutral buoyant (or slightly positive) when carrying special tools or equipment (such as tree-jumper tie-in tools, tool basket, etc). The ROV shall be capable of a through frame lift of 2000 kg (in air). The ROV hydraulic power pack shall have spare valves to be able to operate two functions bi-directional at an operating pressure of 210 bar.

4.9

Survey ROV

ROV in charge of seabed survey operations must have the following characteristics to efficiently perform its tasks: •

high video capacity. Survey ROV must be equipped with several high resolution colour cameras, powerful lighting system and great capacity of data transmission.

•

great propulsion capacity to be able to rapidly perform the survey of large areas (e.g. 5-6 knots during pipeline as-laid survey).

Typical survey ROV characteristics are as follows: • • • • •

propulsion: manipulators: cameras: lights: sensors:

100hp (minimum) 1 x seven-function and 1 x grabber 1 SIT, 3 S-VHS cameras and possibility to add more cameras 18 x 250 Watt (dry quartz halogen lamp) Gyro, depth sensor, sonar, etc.

It must also be equipped with a junction box allowing to add typical survey instruments such as:

• • • • • •

trench profiler bathymetric system boom cameras cathodic protection detection systems pipe tracker, holiday detector (insulation coating defects) side-can sonar (e.g. free-span measurement), etc

Figure 4.18: "Stolt Comex Seaway SOLO survey ROV"



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5

REMOTELY OPERATED TOOLS

5.1

General

ROT are tool systems either actuated from the surface (with ROV for backup functions) or operated by ROV. They are preferred to free-flying ROVs when high lifting or pulling capacities are required. ROT are generally used for the following subsea tasks: •

to perform the replacement or installation of heavy components

•

to install and connect flowlines and umbilical

ROTs are deployed and lowered by means of LARS, lift wires and umbilical, with either dedicated thrusters or ROV assistance for lateral guidance (guideline method is excluded for deepwater applications). Interfaces of ROT remain the same as the interfaces defined in chapter 2 for ROV systems.

5.2

Component Change-Out tools

The Component Change-Out tool is mechanical ROV Operated Tool designed to recover and re-install subsea modules such as: • Subsea Control Module • Insert Choke Module • Retrievable Chemical Injection Unit • Multi-phase Flow Meter • etc. Lift wire attachement point Latch unit

Swivel Hydraulic cylinder for soft landing

Orientation device (steel bar)

Module protection cover

Figure 5.1 - "Kongsberg Module Replacement Tool" Rev. 0 30/09/2000 DGEP/SCR/ED/TA


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An example of CCO can be the Kongsberg Module Replacement Tool (MRT). The MRT is a ROV operated tool deployed by means of lift wire; an orientation device provides attachment point to ROV manipulator and allows the ROV to guide and perform rough alignment. The launching of the MRT is similar to a ROV launching (i.e. by means of LARS). Connection and disconnection of modules is carried out using an ROV operated torque tool. Its main characteristics are:

5.3

•

weight in air:

1200kg (depending on the configuration)

•

dimensions:

1m x 1m x 2.2m in transport mode (LxWxH)

Pull-in and connection tools

Pull-in and connection ROTs for pipeline, flexible pipe and umbilicals are further detailed in the SEAL Engineering document "Tie-in methods", part of the Deepwater Field Development Reference Book. Basically, the ROT systems can be either two tools deployed independently, one for initial pull-in operation and one for the connection phase, or one single tool combining both tie-in sequence. The historical evolution of the tie-in tool technology is as follows: •

the first generation was composed by two-ROT system (one pull-in tool and one connection tool)

•

single tool ROT, combining both functions of pulling and connecting, were designed as an evolution of the first generation

•

ROV-mounted tools (by means of tool skid, see chapter 6) represent the latest improvement for deep to ultra deep water depths. Linear pullin winch

ROV panel

Guiding funnel

Torque tool for clamp tie-in

Figure 5.2 - Kvaerner Pull-In & Connection Tool (PICT)



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These tools include all necessary functions to perform their task; ROV is only used to help during the deployment (i.e. to guide the ROT to the connection location and align it), to attach the pull-in cable at the flowline extremity and eventually to activate back-up functions. ROT(s) (one single or two tools for a tie-in operation) particularly include: •

guiding device (e.g. funnel) to perform rough alignment of the outboard hub during the pull-in sequence

•

either a subsea winch or a linear winch with cable coming from surface, to perform the pull-in operation

•

dedicated tools to retrieve protection cap and clean the hubs

•

connector and sealplate

•

dedicated tools to perform the connection (i.e. positioning of the connector, tightening of screw in case of a clamp connector or hydraulic activation in case of a collet connector, etc.)

•

external seal testing system

The design maximum operating depth of tie-in ROTs is about 500m, for practical reasons related to the encumbrance of lifting wire and umbilical deployment from the surface support vessel. For deeper water an ROV mounted tie-in tool is the preferred alternative.



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6

ROV TOOLS

6.1

General

This chapter aims to describe the main ROV tools (i.e. descriptions and functions). The list is not exhaustive and the description remains general as various tools exist and some of them can be custom-made for special applications. Additional tools are added, depending on the tasks to be performed by the ROV. Such ROV tools (interface tooling), so far as possible, should be designed to operate with a range of ROVs and not limited in application to one type of ROV (i.e. tool dimensions, payload, power supply, etc). All the deepwater ROV tools and equipment shall be rated to the adequate water depth.

6.2

Tool handling and implementation

Four main ROV tooling configurations can be adopted to perform subsea tasks: •

ROV fitted with manipulators

•

ROV equipped with Tool Deployment Unit (TDU)

•

ROV with toolskids or handling frame

•

a combination of above (e.g. manipulators + toolskid).

Manipulator arm is a flexible way to perform subsea tasks, either directly using the manipulator gripper or a manipulator held tool. Deepwater ROV manipulator is typically either five-function arm, which mainly plays the role of grabber, or seven-function arm with high versatility. In return of this operational flexibility, attention must be paid to: •

precision and repeatability of the task to be performed to evaluate the suitability of manipulator.

•

weight of any manipulated component, which must be checked with reference to the manipulator handling enveloppe capacity.

•

location of the interfaces with regards to the manipulator working envelope.

•

mechanical resistance of tools and interfaces, which must resist the loads applied by the manipulator.

•

ROV stabilisation method used which must allow the complex manipulation operation of the arm.

The Tool Deployment Unit (TDU) is a tooling package comprising one or two docking probes and a tool mounted on a cartesian carriage arrangement. The TDU is installed at the front (or the rear) of the ROV in addition to or in replacement of the manipulators. The docking point(s) provide stability and accurate positioning while the one-, two- or three-degree of freedom carriage arrangement allows the tool head to access one or several intervention interfaces.



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Tool head (1 degree of freedom)

Tool head (3 degree of freedom)

Docking probe

Figure 6.1

Figure 6.2

"Single point docking TDU"

"Twin point docking TDU"

A tool skid can be installed under the ROV vehicle in order to perform: •

either the installation of component (such as control pods and chokes)

•

or the installation and connection of flowlines or umbilical (hydraulic or electric connections).

•

dredging or pumping skid, etc

Tool skid can be either surface connected to the ROV vehicle, involving a dual LARS deployment (ROV through frame lift capability), or integrated at the seabed level (e.g. ROV flying and docking onto the tool skid).



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6.3


Hydraulic control intervention tools (hot stabs)

A hydraulic control intervention tools, or hot stabs are designed to provide remotely actuated subsea functions via the ROV. Hot stabs mainly consist in an insert style male probe, fitted with internal hydraulic gallery and ports, used in combination with a female receptacle mounted on the subsea structure or subsea tool (e.g. ROT override function). Single or multiport versions are available; in the last case each separated section is isolated from the others by seals. They are typically used for: •

hydraulic activation of valves

•

testing of connection sealing

•

overriding of existing systems

Manipulator or TDU can operate hot stabs.

Hydraulic ports

seals

T-bar for ROV handling

Figure 6.3 - "Female and male dual hot stab"



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6.4


Rotary torque tools

Rotary torque tools output a rotary motion generally using a hydraulic motor (2-10 HP range) ; all working drive components are positioned within oil compensated housing to avoid water ingress. Rotary torque tools are used in various ROV applications such as: •

actuating manual gate valves

•

tightening screw (e.g. clamp connector)

•

overriding or operating subsea tree valves

•

completing lockout operations of SCSSV circuits

•

operating running tools

•

releasing shackles

•

etc

The rotary interface is standardised by the ISO-13628 (Part 8) for low torque and high torque: •

low torque (i.e. up to 75Nm) interface on SPS consists of a "T" bar or paddle enclosed in a tubular housing

•

high torque (up to 7000Nm) interface consists in a square drive stem enclosed in a tubular housing

Reaction fins Figure 6.4 - "Rotary torque tool"



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The design principle of the high torque tools involves no transmission of loads to the ROV: reaction against the torque produced is provided by a pair of reaction fins mounted on the tool and mating the female receptacle.

Reaction fin receptacle

Figure 6.5

Figure 6.6

"Tool driver / reaction fins"

"Rotary intervention receptacle"

Rotary (high) torque tool typical characteristics are as follows: •

length:

650mm

•

diameter:

310mm

•

weight in air:

50kg

•

maximum torque:

2700Nm (typical)

•

output speed:

0.7 – 1.9 rpm



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6.5


Linear valve override tools

The functions of this type of tool are to actuate, override and lock open various gate valves requiring a push action. The reaction against the pushing force produced is internally reacted by tool: the interface consists in a flange surrounding a central stem. The ROV mounted tool is engaged upon the interface and locked onto the flange. Once installed and locked into place, the tool provides a linear ram that is counteracted by the interrupted flange. Typical linear valve overriding tool characteristics are: •

weight in air:

•

maximum output force: 50 – 70ton

60kg

ROV Handle

0

2

1

4

3

6

5

Hydraulic Jack

Figure 6.7 - "Linear Valve Override Tool"



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6.6


Dredge / jet pump system

This tool is a ROV mounted hydraulic pump unit, which has several functions such as: •

Removal of mud located on landing areas (e.g. x-mas tree, manifold)

•

Suction kit for levelling of templates or installation of suction anchors, etc

•

Water jet cleaning tool (e.g. seal faces) by reversing the pump direction of rotation

Typical technical descriptions are as follows: •

Dimensions:

0.4m x 0.4m x 0.3m (LxWxH)

•

Weight:

30kg – 50kg (20kg – 30 kg submerged)

•

Water flow output:

minimum 200 l/minute at 2-5 bar

•

Hydraulic pump:

minimum 25 l/minutes (adjustable) at 140 bar (8-10 Hp)

Hydraulic Pump

Water Jet / Pump

Figure 6.8 - "Dredge / jet pump system"



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6.7


Hydraulic cable cutter

Hydraulic cable cutter is a gate hydraulic operated ROV tool for cutting either soft line or hard line wire rope (up to 3” OD). It is generally handled and positioned by means of manipulator. Cutting Blade Guiding Blades ( Qty 2 )

Hydraulic Jack

3" OD cable

Figure 6.9 - "Hydraulic cable cutter for 3”OD cable”

6.8

Flowline hub cleaning tool

The flowline hub-cleaning tool is a hydraulic operated ROV tool for cleaning of the flowline hubs. It exists in mono- and multibore hub versions. It is composed of rotating brushes and can include cameras in order to inspect the hub. This type of tool is used to clean a flowline hub prior to either a connection or a seal replacement operation. Typical characteristics of 9" flowline hub cleaning tool are: •

Dimensions:

0.1m x 0.5m x 0.9m (LxWxH)

•

Weight in air:

30kg

•

Weight in water:

20kg



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6.9


Seal replacement tool

This is a ROV back-up tool used to replace the sealplate and/or the gasket inside the flowline connectors with a new sealplate if this should be required. Seal replacement tools are generally designed to be used in combination with a flowline cleaning tool. A seal replacement operation basically consists in: 1. deploying the ROV fitted with the seal replacement tool (SRT). The deficient connector has been previously opened and stroked back. 2. once ROV is docked, the SRT is lowered, by means of a tool elevator, in front of the sealplate. 3. the SRT grips the sealplate and pulls it. 4. the ROV, the SRT and the sealplate are recovered. The sealplate is inspected. 5. in parallel with the inspection of the sealplate, the flowline hub cleaning tool is deployed by ROV and performs the cleaning of the inboard hub, which was containing the sealplate. 6. the sealplate fitted with new seals is lowered, positioned and re-installed by the SRT. 7. the connection is then performed and tested. Typical characteristics of 9" flowline seal replacement tool are as follows: •

Dimensions:

0.4m x 1.2m x 1.2m (LxWxH)

•

Weight in air:

70kg

•

Weight in water:

15kg

Figure 6.10 - "Seal Replacement Toll"



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6.10


Hydro-acoustic measurement tool

Accurate measurements are required by some subsea operations such as steel jumper based tie-ins (see the document "Tie-in methods", sections "5.9 Steel jumpers" and "7.2 Acoustic base line"). A hydro-acoustic measurement tool consists in four transponders arranged by pairs, which are installed by the ROV on fixed points of the two subsea structures (e.g. SPS, PLEM) to be connected. Each of the pairs of transponders is mounted on a frame, which fixes them in a known relative 3D positions. The ROV handles this framework carrying a pair of transponders and installs it on a predetermined and fixed location on the subsea structure.

Figure 6.11 - "Hydro-acoustic measurement tool" Depth sensors are housed in each transponder. Once both pairs are installed (two other transponders can be positioned on the seabed for more accuracy), the relative position and orientation of the two subsea structure can be determined by measuring the distances between each transponders and fixing their relative depth. This technique typically allows for accuracy better than +/- 5cm (over a 50m length) and 1° on relative headings. The typical characteristics of a hydro-acoustic measurement tool are: •

dimensions:

2.7m x 0.7m x 1.2m (LxWxH)

(one pair of transponders assembly) •

weight in air:

90kg

(one pair of transponders assembly) •

nominal measurement: 0 – 75m



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6.11


Taut wire metrology

The taut wire metrology and its applications are fully described in the document "Tie-in methods", section 7.3. Main assembly

Measurement cable

Subsea structures Figure 6.12 - "Taut wire measurement tool" A taut wire measurement tool consists in two assemblies installed by the ROV on the two subsea structures, of which the relative position must be determined. Each of the two assemblies is fitted with guiding pins to accurately position it on a known location on the subsea structure. Once installed, the ROV deployed a cable between them, which is tensed by a winch part of the main assembly (i.e. containing the cable, the winch, the measuring wheel, etc.). The measurements are performed using the ROV video to read the various gauges on the tool: • The vertical elevation difference and angular misalignment between the two tie-in points is determined by means of the protractors and dual axis inclinometers. A resolution of 1° can be achieved. • The distance between the two points is determined from the length of the taut line. This length is measured from a calibrated measuring wheel mounted near the winch. This counter can achieved an accuracy of +/-3cm (over a 50m length) with correction of the wire catenary shape.



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Figure 6.13 - "Taut wire measurement tool scheme" The typical characteristics of a taut wire measurement tool are as follows: •

Main assembly dimensions:

•

Main assembly weight in air:

130kg

•

Normal measurement:

0 – 50m


0.7m x 0.7m x 1.1m (LxWxH)


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6.12


ROV-mounted pull-in and connection tool

Pull-in and connection tools are described in the section "Tie-in methods", part of the Deepwater Field Development Reference Book. ROV-mounted pull-in and connection tools represent the latest generation of tie-in tool. These systems are typically composed of an interface skid which is mounted under the ROV, a pull-in and connection tool which can be deployed independently from the ROV and a tie-in porch which interfaces with the subsea structure. All these tools can be operated by means of a working class ROV deployed from a dedicated ROV support vessel. The ROV mounted tools have the following general characteristics: • Maximum pull-in force:

30ton

• Pull-in distance:

from 3m to 40m

• Angular alignment:

+/-15°

• Tool weight (in air):

8-10ton

ROV

Tool skid

Figure 6.14 - Services skid integrated

Figure 6.15 - Flexconnect

to TRITON XL ROV

Pull-In Module (PIM)



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ANNEX 1 Deepwater ROV



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CLASS II OBSERVATION & LIGHT WORK ROVs

Unit GENERAL Manufacturer Type Operating depth Total Power Built today DIMENSIONS Length Width Height Weight HP & PROPULSION Power Thtusters Forward thrust Lateral thrust Vertical thrust Speed forward Speed lateral Speed vertical INSTRUMENTATION Camera SIT system Camera CCD system Navigation sonar Sensor system Data transmission Auto heading Auto depth Auto altitude

m hp ea

SCORPION

DRAGON

HYSUB 50

SEAL

Perry Tritech Perry Tritech Class II Class II 1000-2000 1000-2000 50 75 15+ 23+

Hydrovision Class II 2 010 60 ?

ISE Class II 2 010 50 ?

Racal TTI Class II 600 50 3

MAX ROVER MK II DSSI Class II 2 000 40 ?

m m m kgp

2,50 1,04 1,42 1 000

2,03 1,14 1,44 1 367

2,00 1,20 1,10 850

2,50 1,40 1,60 1 820

1,50 1,00 1,00 750

2,23 0,90 1,21 750

hp ea kgf kgf kgf knots knots knots

50 1 V - 3H 163

75 3V-3H

50 3V-4H

3,00 2,00 1,50

3,00 1,70 1,00

60 2V-4H 350 300 225 3,50 2,50 1,50

50 2V-4H 250 250 150 3,40 1,10

40 2V-4H 172 30 25 3,50 1,35 1,50

+/- 2 +/- 15 option

ROS ROS Tritech gyrocompass fiber optics yes yes yes

Osprey Osprey Imagenex gyrocompass fiber optics yes yes yes

Mesotech gyrocompass fiber optics +/- 4 +/- 10 +/- 10

Slingsby no

Slingsby no

Hydrovision no

TA-16

TA-16

1x5F

ISE no 45 1 1 120 1 x 5F

1x7F 50 1,6 1 080 no

170 680

204 454

50 500

90

OSEL top hat 1 30

ISE side entry 1,5

Insite Gemini Insite Orion UDI gyrocompass fiber optics ° +/- 2 cm +/- 15 cm option

MANIPULATORS 7F manipulator Load capacity Reach Torque 5F Grabber manipulator

ea kg m Nm ea

SUPPORT FUNCTIONS Payload Through Frame Lift

kgp kgp

LAUNCH SYSTEM TMS (vehicle entry) Cage weight tons Launch speed m/mn Main Umbilical OD mm Umbilical submerged weight kg/m Umbilical working load tons Tether length m SHIPBOARD SUPPLY Power required KVA Frequency Hz


VIPER

top hat 1,68 43 9 200 175 60

150 75


flux gate +/- 3,5 +/- 30 +/- 30

no

1x4F

80-100 600

80

side entry

top hat 0,5

32 2,7 5 170

150

110 60

175 50-60

28 1,5 5 102

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CLASS III DRILLING & WORKING ROVs

Unit MAGNUM MILLENIUMEXAMINER CLANSMAN TRITON XL GENERAL Manufacturer Type Operating depth Total Power Built today DIMENSIONS Length Width Height Weight HP & PROPULSION Power Thtusters Forward thrust Lateral thrust Vertical thrust Speed forward Speed lateral Speed vertical INSTRUMENTATION Camera SIT system Camera CCD system Navigation sonar Sensor system Data transmission Auto heading Auto depth Auto altitude MANIPULATORS 7F master/slave manipulator Load capacity Reach Torque 5F Grabber SUPPORT FUNCTIONS Payload Through Frame Lift HPU Pressure Flow LAUNCH SYSTEM TMS (vehicle entry) Cage weight Launch speed Thrustered cage Main Umbilical OD Umbilical submerged weight Umbilical working load Tether length SHIPBOARD SUPPLY Power required Frequency Rev. 0 30/09/2000 DGEP/SCR/ED/TA

m hp ea

Oceaneering Oceaneering Subsea Off. Class III Class III Class III 2 500 3000 + 2 000 100 150 100 50+ 15+

Subsea Off. Class III 2000-3000 120 5

2,54 1,47 1,60 1,60

3,00 1,50 1,70 1,90

2,00 1,95 1,80 1,70

2,00 1,70 1,80 2,20

3,09 1,52 1,85 3,30

hp ea kgf kgf kgf knots knots knots

2 x 50 4V-4H 520 475 395 3 2 2

2 x 75 4V-4H 520 475 395 3 2 2

75 4V-4H 560 560 560

120 2V-4H 704 704 250 3,25 2,40 2,40

100 3V-4H 660 500 580 2-3 2 1

kgp kgp hp psi l/mn

tons m/mn hp mm kg/m tons m KVA Hz

160 910 2x50 3 000 155 Dynacon side entry 2,00

160 910 2x75 3 000 155 Dynacon side entry 2,00

50 40

50 40

16 180

16 200

200 60

250 60

1

1

no

50 3 000 100 3 000 166

40 3 000 80 side entry 3,0 150 no

200

3,37 1,50 1,88 4,20

3,37 1,50 1,88 4,70

4V-4H 550 550

4V-4H 550 550

3,25 2,40 2,40

3,25 2,40 2,40

Osprey Insite Gemini Osprey Osprey Insite Orion Osprey Imagenex UDI UDI gyrocompass gyrocompass gyrocompass fiber optics fiber optics fiber optics +/- 2 +/- 1 +/- 15 +/- 8 +/- 15 +/- 10 Kraft Slingsby 2 2 x Predator 2 x TA40 210

no

4,5 25 300

OLYMPIAN

Perry Tritech SEL Slingsby SEL Slingsby Class III Class III Class III 2 000-6 000 2 000 3 000 100 - 150 200 120 20+ 10+ 1

m m m tons

Simrad Simrad Simrad Simrad Mesotech Mesotech gyrocompass gyrocompass fiber optics fiber optics ° yes yes cm yes yes cm yes yes Schilling Schilling ea 2 x Conan 2 x Conan kg 170 170 m 1,7 1,7 Nm ea no no

MRV

top hat 2,81 30 no 46 16,75 200

400 no 250 3 700 75 3 000 112 Hydralift top hat 2,30

2,95 1,84 2,00 3

2,97 1,53 1,95 4,77

3,40 2,10 2,10 4,70

2,20 1,40 1,60 1,80

100 3V-4H 700 700 300 3,10

200 3V-4H 920 920 480

2 x 75 4V-4H 700

100 2V-4H 700 700 300 3,75 2,25

2 x 80 4V-4H

Osprey Osprey UDI gyrocompass fiber optics +/- 1 +/- 8 +/- 10 Slingsby 1 X Hydrus 114 2

ROS ROS Tritech gyrocompass fiber optics yes yes yes Hydrovision 1 x RTL 7

Gemini Apollo Tritech optic gyro fiber optics +/- 1° +/- 15 yes Schilling 1 x Titan III

Mesotech gyrocompass fiber optics +/- 1,5 +/- 10 +/- 10

Mesotech gyrocompass fiber optics +/- 1,5 +/- 10 +/- 10

1 x TA9

1 x RTL 5

Rigmaster

2 50 1,6 108 no

2 50 1,6 108 no

250 3 700 75 3 000 112

500 3 000 50 2 500 10 Hydralift top hat

300 2 000 150 3 000

500 5 000 2 x 75 3 000 265

200-300 5 000

200-300 5 000

Dynacon top hat 2,9 30 - 60 no 33 3,22 28,8 250 - 1000

side entry 1,80 50 no 36 2,9 25 200

both

both

no

no

200

200

240 60

250 50-60

250 50-60

top-hat

48 4,1 8,5 230

45

250 60 DEEPWATER ROV AND TOOLS

DEMON INNOVATOR HYSUB 150 SEALION II SEA SERPENT DIABLO MK II Hydrovision Sonsub Int. ISE Racal TTI Racal TTI Class III Class III Class III Class III Class III 2 000 3 000 2 500 1 000 2 500 150-200 150 100 160 5 5 26 1

9 200 - 600 200 180 60

3,5

Osprey Osprey Mesotech gyrocompass fiber optics

ISE 2 x Magnum 120 1,5 1 120 no

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ANNEX 2 ROV Contractors and Manufacturers



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ANNEX 2.1 ROV CONTRACTORS

COFLEXIP STENA OFFSHORE INTERNATIONAL 88 avenue du Général Leclerc Boulogne – Billancourt 92100 France Tel : 01 47 12 80 00 Fax : 01 47 12 80 10 GLOBAL INDUSTRIES OFFSHORE INC. 900 Halliburton center 5151 San Felipe Houston 77056, Texas Tel : 01 713 624 2222 Fax : 01 713 624 2220 OCEANEERING INTERNATIONAL LTD Pitmedden Road Dyce, Aberdeen AB21 0DP, Scotland Tel : 44 1224 770444 Fax : 44 1224 771583 ROCKWATER LIMITED Wellheads Crescent Wellheads Industrial Estate Aberdeen AB2 0GA, Scotland Tel : 44 1224 777000 Fax : 44 1224 777731



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STOLT COMEX SEAWAY SA 467 chemin du Littoral BP 69 13321 Marseille Cedex 16 France Tel : 04 91 09 68 01 Fax : 04 91 09 68 00 RACAL TTI PTE LTD 45 Joo Koon Circle Singapore 62 9106 Tel : 65 862 1233 Fax : 65 861 8938 SONSUB INTERNATIONAL LTD Tern Commercial Park Denmore Road Bridge of Don Aberdeen AB23 8JX, Scotland Tel : 44 1224 843400 Fax : 44 1224 843435 SUBSEA OFFSHORE LTD Greenwell Base Greenwell Road Aberdeen AB1 4AX, Scotland Tel : 44 1224 292000 Fax : 44 1224 879312



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ANNEX 2.2


ROV MANUFACTURERS

HYDROVISION LTD Howe Moss Avenue Kirkhill Industrial Estate Dyce, Aberdeen AB21 DGP, Scotland Tel : 44 1224 772150 Fax : 44 1224 772166 INTERNATIONAL SUBMARINE ENGINEERING LTD 1734 Broadway Street, Port Coquitlam BC Canada V3C 2M8 Tel : 1 604 942 5223 Fax : 1 304 942 7577 PERRY TRITECH INCORPORATED 821 Jupiter Park Drive Jupiter, Florida 33458 Tel : 1 561 743 7000 Fax : 1 561 743 1313 SLINGSBY ENGINEERING LTD Kirkbymoorside, York YO6 6EZ, England Tel : 44 1751 431751 Fax : 44 1751 431388 OCEANEERING (see 2.1) RACAL TTI PTE LTD (see 2.1) SUBSEA OFFSHORE LTD (see 2.1)



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