Total-Deepwater Reference Book[1]
Short Description
Sub Sea...
Description
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 With the passage of time the information contained within this document will be superseded as new technology is brought onto the market.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
Page 1
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
PREFACE
Page 2
DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK SUBSEA PRODUCTION SYSTEMS
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
Page 1
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 2
TotalFinaElf
3
SUBSEA PRODUCTION MANIFOLDS AND TEMPLATES......................................... 63 3.1
4
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 3
TotalFinaElf
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
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 4
TotalFinaElf
1
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 5
TotalFinaElf
1.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 6
TotalFinaElf
• • • • • • • • • • • • •
1.2.2 • •
1.2.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 7
TotalFinaElf
• • • • •
1.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 8
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 9
TotalFinaElf
DEEPWATER REFERENCE BOOK
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):
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 10
TotalFinaElf
Through-Bore Tree: Tree Connector:
Tree Mandrel:
Tree Running Tool:
Tubing Hanger:
DEEPWATER REFERENCE BOOK
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:
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
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.
SUBSEA PRODUCTION SYSTEMS
Page 11
TotalFinaElf
2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 12
TotalFinaElf
2.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 13
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 14
TotalFinaElf
2.2.3
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 15
TotalFinaElf
2.2.4
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 16
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 17
TotalFinaElf
2.2.6
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 18
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 19
TotalFinaElf
2.2.7
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 20
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 21
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 22
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 23
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 24
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 25
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 26
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 27
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 28
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 29
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 30
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 31
TotalFinaElf
2.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
Tubing Head Spool
Tubing Hanger
SUBSEA PRODUCTION SYSTEMS
Subsea Wellhead
Page 32
TotalFinaElf
2.3.2
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 33
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 34
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 35
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 36
TotalFinaElf
•
•
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 37
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 38
TotalFinaElf
•
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 39
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 40
TotalFinaElf
•
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 41
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 42
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 43
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 44
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 45
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 2.30 - Examples of Tree Cap Running Tools
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 46
TotalFinaElf
•
•
•
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 47
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 48
TotalFinaElf
•
•
•
• •
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 49
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 50
TotalFinaElf
2.3.6
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 51
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 52
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 53
TotalFinaElf
2.3.7
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 54
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 55
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 56
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 57
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 58
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 59
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 60
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 61
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 62
TotalFinaElf
3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 63
TotalFinaElf
3.1.1
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 64
TotalFinaElf
• • • • •
3.1.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 65
TotalFinaElf
3.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 66
TotalFinaElf
•
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 67
TotalFinaElf
3.3 3.3.1
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 68
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 69
TotalFinaElf
• • •
3.3.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 70
TotalFinaElf
3.3.5
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 71
TotalFinaElf
3.3.6
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 72
TotalFinaElf
3.3.7
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 73
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 74
TotalFinaElf
3.4.2
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 75
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 76
TotalFinaElf
3.4.3
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 77
TotalFinaElf
3.4.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 78
TotalFinaElf
4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 79
TotalFinaElf
4.1.1
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 80
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 81
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 82
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 83
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 84
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 85
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 86
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 4.5 - Internal View of a Typical Subsea Pod – The Outer Housing Is Yet To Be Installed
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 87
TotalFinaElf
4.1.3
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 88
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 89
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 90
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 91
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 92
TotalFinaElf
4.1.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 93
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 94
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 95
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 96
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 97
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 98
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 99
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 100
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 101
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 102
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 103
TotalFinaElf
DEEPWATER REFERENCE BOOK
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 104
TotalFinaElf
4.1.5
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 105
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 106
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 107
TotalFinaElf
4.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 108
TotalFinaElf
4.2.1 • • • • • • • • • • •
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 109
TotalFinaElf
4.2.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 110
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 111
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 112
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 113
TotalFinaElf
• • •
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 114
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 115
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 116
TotalFinaElf
4.3.3
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 117
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 118
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 119
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 120
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 4.46 - A Dual Bore Riser System Configured To Run A Subsea Tubing Hanger Inside A Subsea BOP And Marine Riser
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 121
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 122
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 123
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 124
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 125
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 126
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 4.51 - Example Of A Spider For Running Installation And Workover Riser.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 127
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 4.52 - Dual Bore Riser Being Made Up At The Drill Floor. Note Use Of Dedicated Spider For Supporting The Already Suspended Riser.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 128
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 4.53 - Example Of A Spider Used To Run Dual Bore Risers
Figure 4.54 - This Drawing Shows A Typical Spider Design
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 129
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 130
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 131
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 132
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 133
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 134
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 135
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 136
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 137
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 138
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 139
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 140
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 141
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 142
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 143
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 144
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 145
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 146
TotalFinaElf
4.3.5
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 147
TotalFinaElf
5
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 148
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 5.2 - One Example of a Subsea Pumping Module
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 149
TotalFinaElf
5.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 150
TotalFinaElf
5.2.1
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 151
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 152
TotalFinaElf
5.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 153
TotalFinaElf
• • • • • •
5.4.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 154
TotalFinaElf
5.4.4
DEEPWATER REFERENCE BOOK
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
SUBSEA PRODUCTION SYSTEMS
Page 155
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 156
TotalFinaElf
5.5
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 157
TotalFinaElf
6
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 158
TotalFinaElf
6.1.4 • • • • • • •
6.1.5 • •
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 159
TotalFinaElf
6.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 160
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 161
TotalFinaElf
6.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SUBSEA PRODUCTION SYSTEMS
Page 162
DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK SEALINES
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
Page 1
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
INTRODUCTION ....................................................................... ERREUR ! SIGNET NON DEFINI.
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
INTRODUCTION ....................................................................... ERREUR ! SIGNET NON DEFINI.
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 2
TotalFinaElf
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
INTRODUCTION ....................................................................... ERREUR ! SIGNET NON DEFINI.
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
DEEPWATER REFERENCE BOOK
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
INTRODUCTION ....................................................................... ERREUR ! SIGNET NON DEFINI.
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 3
TotalFinaElf
8
9
DEEPWATER REFERENCE BOOK
INSTALLATION TECHNIQUES .................................. ERREUR ! SIGNET NON DEFINI. 8.1
INTRODUCTION ....................................................................... ERREUR ! SIGNET NON DEFINI.
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
INTRODUCTION ....................................................................... ERREUR ! SIGNET NON DEFINI.
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 4
TotalFinaElf
DEEPWATER REFERENCE BOOK
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 5
TotalFinaElf
1.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 6
TotalFinaElf
1.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 7
TotalFinaElf
WD
1.4
DEEPWATER REFERENCE BOOK
= 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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 8
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 9
TotalFinaElf
2.2
DEEPWATER REFERENCE BOOK
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”.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 10
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 11
TotalFinaElf
DEEPWATER REFERENCE BOOK
• 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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 12
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
1.1) 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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 13
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 14
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 15
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 16
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 17
TotalFinaElf
2.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 18
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 19
TotalFinaElf
3.2
DEEPWATER REFERENCE BOOK
Pipeline end terminations
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 20
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 21
TotalFinaElf
3.3
DEEPWATER REFERENCE BOOK
Subsea production system
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 22
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 23
TotalFinaElf
3.4
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 24
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 25
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 26
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 27
TotalFinaElf
4.2.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 28
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 29
TotalFinaElf
•
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 30
TotalFinaElf
•
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 31
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 32
TotalFinaElf
4.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 33
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 34
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Polyamide 11, High Density Polyethylene, Coflon
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
Low, medium or high carbon steel
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 35
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 36
TotalFinaElf
4.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 37
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 38
TotalFinaElf
4.5
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 39
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 40
TotalFinaElf
4.6
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 41
TotalFinaElf
4.7
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 42
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 43
TotalFinaElf
4.8
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 44
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 45
TotalFinaElf
5
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 46
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 47
TotalFinaElf
5.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 48
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 49
TotalFinaElf
5.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 50
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 51
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 52
TotalFinaElf
6.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 53
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 54
TotalFinaElf
6.2.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 55
TotalFinaElf
6.2.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 56
TotalFinaElf
6.2.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 57
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 58
TotalFinaElf
6.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 59
TotalFinaElf
6.3.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 60
TotalFinaElf
6.3.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 61
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 62
TotalFinaElf
7.2
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 63
TotalFinaElf
DEEPWATER REFERENCE BOOK
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 64
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 65
TotalFinaElf
7.3
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 66
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 67
TotalFinaElf
DEEPWATER REFERENCE BOOK
♦ -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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 68
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 69
TotalFinaElf
DEEPWATER REFERENCE BOOK
Digging chain Motorised track
Figure 42 - Other type of digging chain trencher
Cutting wheel
Figure 43 - Trencher with cutting wheel
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 70
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 71
TotalFinaElf
DEEPWATER REFERENCE BOOK
Figure 44 - Feeding vessel
Figure 45 - Trailing suction hopper dredger
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 72
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 73
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 74
TotalFinaElf
7.5.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 75
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 76
TotalFinaElf
8.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 77
TotalFinaElf
8.3
DEEPWATER REFERENCE BOOK
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 78
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 79
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 80
TotalFinaElf
8.4
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 81
TotalFinaElf
8.5
DEEPWATER REFERENCE BOOK
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.)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 82
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 83
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
rd
st
SEALINES
Page 84
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 85
TotalFinaElf
9.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 86
TotalFinaElf
9.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 87
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 88
TotalFinaElf
DEEPWATER REFERENCE BOOK
ROV
ROV retrievable instrument unit
FSM Station
Subsea connector Com. connector Pipeline
Figure 59 - FSM system in subsea remote monitoring
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 89
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 90
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 91
TotalFinaElf
10.2
DEEPWATER REFERENCE BOOK
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
•
Only for piggyback bundle to main flowline
•
Water depth limitation (1000m1500m)
6. Bundle with wet carrier
•
Not recommended
•
Only for piggyback bundle to main flowline
•
Only for piggyback bundle to main flowline
•
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 92
TotalFinaElf
11
DEEPWATER REFERENCE BOOK
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
SEALINES
Page 93
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 94
TotalFinaElf
11.4
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 95
TotalFinaElf
11.6
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 96
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
-
Good corrosion resistance
-
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
-
Medium purchase cost
-
Field welding to be qualified
-
Medium corrosion resistance
-
Medium installation cost
-
Low operating cost
-
Medium purchase cost
-
Medium installation cost
-
High U value increasing with time
-
Low compressive strength
-
Low installation cost
-
High purchase cost
-
Flexibility on seabed “snagging”
-
Temperature limitation
-
Re-usable
-
Potential problems due to WD:
-
Good corrosion resistance
1. ‘’Bird cages’’
-
Low operating cost
2. ‘’Reverse end cap effect’’
-
Medium installation cost
-
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
-
Low installation cost
-
-
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
SEALINES
Page 97
DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK RISER SYSTEMS
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
Page 1
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 2
TotalFinaElf
4
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 3
TotalFinaElf
9
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 4
TotalFinaElf
1
INTRODUCTION
1.1
Scope
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 5
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 6
TotalFinaElf
1.4
DEEPWATER REFERENCE BOOK
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
We wish to thank the manufacturers and subsea contractors for the provision with courtesy of technical information and photographs of their products.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 7
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 8
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 9
TotalFinaElf
2.2.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 10
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 11
TotalFinaElf
2.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 12
TotalFinaElf
2.3.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 13
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 14
TotalFinaElf
2.4
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 15
TotalFinaElf
DEEPWATER REFERENCE BOOK
3
INTERFACE REQUIREMENT
3.1
General
The main interface requirements in the riser design are related to: -
Pipeline end terminations
-
Subsea production system
-
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 16
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 17
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 18
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 19
TotalFinaElf
3.3.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 20
TotalFinaElf
3.3.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 21
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 22
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Polyamide 11, High Density Polyethylene, Coflon
Interlocked steel carcass
Galvanized steel, AISI 3O4, AISI 304L, AISI 316, AISI 316L, Duplex, etc.
Thermoplastic sheath
Polyamide 11, High Density Polyethylene, Coflon
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
Low, medium or high carbon steel
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
RISER SYSTEMS
Page 23
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 24
TotalFinaElf
4.2.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 25
TotalFinaElf
4.2.4
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 26
TotalFinaElf
4.2.5
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 27
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 28
TotalFinaElf
III.
DEEPWATER REFERENCE BOOK
"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
RISER SYSTEMS
Page 29
TotalFinaElf
V.
DEEPWATER REFERENCE BOOK
"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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 30
TotalFinaElf
VI.
DEEPWATER REFERENCE BOOK
"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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 31
TotalFinaElf
I.
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 32
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 33
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 34
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 35
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
Page 36
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 37
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 38
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 39
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 40
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 41
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 42
TotalFinaElf
DEEPWATER REFERENCE BOOK
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 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
Thermal conductivity
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 46
TotalFinaElf
5.4
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 47
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 48
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 49
TotalFinaElf
6.1.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 50
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 51
TotalFinaElf
6.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 52
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 53
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 54
TotalFinaElf
7.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 55
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 56
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 57
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 58
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 59
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 60
TotalFinaElf
8.2.2
DEEPWATER REFERENCE BOOK
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
Produced fluid + Gas
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 61
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 62
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Table 9 – Main equipment list 3
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 63
TotalFinaElf
8.2.4
DEEPWATER REFERENCE BOOK
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
Produced fluid + Gas
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
RISER SYSTEMS
Page 64
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Table 11 – Main equipment list 4
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 65
TotalFinaElf
DEEPWATER REFERENCE BOOK
9
INSTALLATION TECHNIQUES
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 66
TotalFinaElf
9.2
DEEPWATER REFERENCE BOOK
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 67
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 68
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 69
TotalFinaElf
9.2.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 70
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 71
TotalFinaElf
9.2.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 72
TotalFinaElf
DEEPWATER REFERENCE BOOK
A typical installation procedure would consist of the following phases (see figure 39): 1.
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 73
TotalFinaElf
9.2.4
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 74
TotalFinaElf
DEEPWATER REFERENCE BOOK
A typical installation procedure would consist of the following phases (see figure 40): 1.
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 75
TotalFinaElf
9.2.5
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 76
TotalFinaElf
DEEPWATER REFERENCE BOOK
A typical installation procedure would consist of the following phases (see figure 41): 1.
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 77
TotalFinaElf
9.2.6
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 78
TotalFinaElf
DEEPWATER REFERENCE BOOK
A typical installation procedure would consist of the following phases (see figure 42): 1.
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 79
TotalFinaElf
DEEPWATER REFERENCE BOOK
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:
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 80
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 81
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 82
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 83
TotalFinaElf
9.3.4
DEEPWATER REFERENCE BOOK
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
RISER SYSTEMS
Page 84
TotalFinaElf
II.
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 85
TotalFinaElf
DEEPWATER REFERENCE BOOK
10
APPLICATIONS & LIMITATIONS
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
RISER SYSTEMS
Page 86
TotalFinaElf
10.3
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 87
TotalFinaElf
DEEPWATER REFERENCE BOOK
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 88
TotalFinaElf
11
DEEPWATER REFERENCE BOOK
ADVANTAGES & DISADVANTAGES
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
- 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.
RISER SYSTEMS
Page 89
TotalFinaElf
Configuration
Steep S
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 90
TotalFinaElf
Configuration
Pliant wave
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 91
TotalFinaElf
Configuration
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 92
TotalFinaElf
Configuration
C - Top tensioned riser (Spar)
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 93
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
RISER SYSTEMS
Page 94
DEEPWATER FIELD DEVELOPMENT REFERENCE BOOK UMBILICALS
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
Page 1
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 2
TotalFinaElf
5.
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 3
TotalFinaElf
1
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 4
TotalFinaElf
1.2
DEEPWATER REFERENCE BOOK
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
Definitions & Abbreviations
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 5
TotalFinaElf
1.4
DEEPWATER REFERENCE BOOK
References 1.
Offshore technology conference papers from 1969 to 1998
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
We wish to thank the manufacturers and subsea contractors for the provision with courtesy of technical information and photographs of their products.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 6
TotalFinaElf
2
DEEPWATER REFERENCE BOOK
INTERFACE REQUIREMENT
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
-
Subsea production system
-
Installation equipment & vessel
The above requirements are described in the following sections.
2.2
Floating production system
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 7
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 8
TotalFinaElf
2.2.3
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 9
TotalFinaElf
2.4
DEEPWATER REFERENCE BOOK
Subsea production system
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 10
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 11
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 12
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 13
TotalFinaElf
DEEPWATER REFERENCE BOOK
Horizontal powered reel
Overboarding chute
Figure 09 – Umbilical laying vessel – Seaway Condor
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 14
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 15
TotalFinaElf
3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 16
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 17
30/09/2000 DGEP/SCR/ED/TA Outer sheath
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 18
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 19
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 20
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 21
TotalFinaElf
DEEPWATER REFERENCE BOOK
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).
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 22
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 23
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 24
TotalFinaElf
Steel tubes
DEEPWATER REFERENCE BOOK
Binding tape
Polyethylene
Electrical
sheathed
cables
tubes Armour layers
Figure 21 – Typical hydraulic steel tube umbilical (for both static and dynamic applications)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Figure 22 – Dynamic electro-hydraulic steel tube umbilical
Page 25
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Polyethylene outer sheath
Figure 24 – Static electro- hydraulic steel tube umbilical
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 26
TotalFinaElf
3.4
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 27
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 28
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 29
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Polyethylene outer sheath
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 30
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 31
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 32
TotalFinaElf
DEEPWATER REFERENCE BOOK
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)
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 33
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 34
TotalFinaElf
3.7
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 35
TotalFinaElf
3.8
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 36
TotalFinaElf
3.9
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 37
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 38
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 39
TotalFinaElf
4.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 40
TotalFinaElf
♦
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 41
TotalFinaElf
4.5
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 42
TotalFinaElf
DEEPWATER REFERENCE BOOK
5.
INSTALLATION TECHNIQUES
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
UMBILICALS
Page 43
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 44
TotalFinaElf
5.2
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 45
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 46
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 47
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 48
TotalFinaElf
5.3.2.2
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 49
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Floating production system
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 50
TotalFinaElf
5.3.2.3
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 51
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 52
TotalFinaElf
DEEPWATER REFERENCE BOOK
6.
APPLICATIONS & LIMITATIONS
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 53
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
UMBILICALS
Page 54
TotalFinaElf
DEEPWATER REFERENCE BOOK
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.
Rev. 0 30/09/2000 DGEP/SCR/ED/TA
UMBILICALS
Page 55
TotalFinaElf
DEEPWATER REFERENCE BOOK
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
Thermal conductivity
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
View more...
Comments
