total-deepwater reference book[1]

SEPTEMBER 2000

Risers

Umbilicals

Subsea ProductionSystems

Tie-in Systems

Subsea ControlSystems

InstallationVessels

ROVS and Tools

Sealines

DEEP W ATER REFERENCE BOOKDEEP W ATER REFERENCE BOOK

TotalFinaElf DEEPWATER REFERENCE BOOK

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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 With the passage of time the information contained within this document will be superseded as new technology is brought onto the market.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


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DOCUMENT REVISIONS

VOLUME NUMBER DESCRIPTION OF REVISION DATE OF REVISION

VOLUME ONE Original Document 30/09/2000

Rev. 0

VOLUME TWO Original Document 30/09/2000

Rev. 0

VOLUME THREE Original Document 30/09/2000

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

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DEEPWATER FIELD DEVELOPMENT

REFERENCE BOOK

SUBSEA PRODUCTION SYSTEMS


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TABLE OF CONTENTS

1 INTRODUCTION............................................................................................................ 5

1.1 SCOPE.................................................................................................................................5

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

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

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

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

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

2 SUBSEA PRODUCTION EQUIPMENT........................................................................ 12

2.1 INTRODUCTION ..................................................................................................................12

2.2 SUBSEA WELLHEADS.........................................................................................................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



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3 SUBSEA PRODUCTION MANIFOLDS AND TEMPLATES......................................... 63

3.1 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

4 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 WORKOVER RISER SYSTEMS ..............................................................113

4.3.1 INTRODUCTION ......................................................................................................113

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

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

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

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

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



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5 FIELD ARCHITECTURE.............................................................................................148

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

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

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

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

5.3 DRILLING AND WELL 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 FUTURE DEVELOPMENT, EXPANSION ...............................................................................157

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

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



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1 INTRODUCTION

1.1 Scope

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

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.

Figure 1.1 - Subsea Production Systems Offer a Cost Competitive Option for Deepwater Field Developments



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1.2 Regulations, Codes and Standards

1.2.1 International Specifications

ANSI B31.3, Chemical Plant Petroleum Refinery Piping.

API RP 2R, Design, Rating and Testing of Marine Drilling Riser Couplings.

API 5A, Specification for Casing, Tubing and Drill Pipe.

API 5AC, Specification for Casing, Tubing and Drill Pipe.

API 5D, Specification for Drill Pipe.

API 5L, Specification for Line Pipe.

API 6A, Specification for Wellhead and Christmas Tree Equipment.

API 6D, Specification for Pipeline Valves.

API 8A, Drilling and Production Hoisting Equipment.

API 14A, Specification for Subsurface Safety Valves.

API 14B, Recommended Practice for Design Installation & Operation of Subsurface Valve Systems.

API 14D, Specification for Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Services.

API 16A, Specification for Drill Through Equipment.

API 17D, Specification for Subsea Wellhead and Christmas Tree Equipment.

API 17G, Design and Operation of Completion / Workover Riser Systems

ASME IX, Welding and Braising Qualifications, Article II Welding Procedure Qualifications and III Welding Performance Qualifications.

ASME V, Boiler and Pressure Vessel Code Section V - Non Destructive Examination.

ASME VIII, Boiler and Pressure Vessel Code Section VIII - Rules for Construction of Pressure Vessels - Division 1 & 2.

ASME/ANSI B16.34, Valves - Flanged, Threaded, and Welding End.

DIN 50049-EN 10 204, Documents on material tests.

DnV Electrical requirements for WOCS

DnV Safety and Reliability of Subsea Production systems

DnV Cert. note 2.7-1 Lifting certificate requirements. ( Offshore containers )

DnV RPB401 Recommended Practice Cathodic Protection Design.

EN 10204, Metallic Products - Types of Inspection Documents

FEA-M 1990, Regulations for Electrical Installation on Maritime Platforms.

IEC 92.101, Electrical Installations in Ships. Definitions and General Requirements

ISO 10423, Specification for Wellhead and Christmas Tree Equipment (Replaces API 6A).

ISO 10432 1, Standard for Subsurface Safety Valves.

ISO 10433, Specification for Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service (Replaces API 14D).

ISO 13628, Petroleum And Natural Gas Industries - Drilling And Production Equipment.

ISO 13628-1, General Requirements And Recommendations.

ISO 13628-2, Flexible Pipe Systems For Subsea And Marine Applications.

ISO 13628-3, TFL Pump Down Systems.

ISO 13628-4, Subsea Wellhead And Tree Equipment.



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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.

1.2.2 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.

1.2.3 NORSOK Standards

Norwegian Subsea Equipment is designed in accordance with the Norwegian Petroleum Directorates (NPD) regulations and the requirements in the following NORSOK specifications.

The NORSOK standards have been developed by the Norwegian petroleum industry as a part of the NORSOK initiative and are jointly issued by OLF (The Norwegian Oil Industry Association) and TBL (Federation of Norwegian Engineering Industries). NORSOK standards are administered by NTS (Norwegian Technology Standards Institution).

1 U-DP-001, Principles for Design and Operation of Subsea Production Systems

2 U-CR-003, Subsea Christmas Tree Systems

3 U-CR-008, Subsea Color and Marking

4 M-DP-001, Material Selection

5 M-CR-101, Structural steel fabrication, Rev. 2, Jan. 1996

6 M-CR-120, Material data sheets for structural steel, Rev. 1, Dec. 1994

7 M-CR-501, Surface preparation and protective coating, Rev. 2, Jan. 1996

8 M-CR-503, Cathodic protection, Rev. 1, Dec. 1994

9 M-CR-505, Corrosion monitoring design, Rev. 1, Dec. 1994

10 M-CR-601, Welding and inspection of piping, Rev. 1, Dec. 1994

11 M-CR-621, GRP piping materials, Rev. 1, Dec. 1994

12 M-CR-630, Material data sheets for piping, Rev. 1, Dec. 1994



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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.

1.3 Definitions and Abbreviations

ADS: Atmospheric Diving Suit

Annulus: The annular space between the production casing and the production tubing.

BOP: Blowout Preventer

Casing: Tubular steel conductors of progressively smaller sizes through which a well is drilled.

Casing Program: The sequence of casing installed in a well. A common casing program is 30 (surface conductor), 20 (surface casing), 13-3/8 (intermediate casing) and 9-5/8 (production casing).

CDU: 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: Distributed Control System

Drill Through Wellhead: 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.

DSV: 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: Electrical Flying Lead

EPU: Electrical Power Unit

ESD: Emergency Shut Down

ESP: Electric Submersible Pump

FAT: Factory Acceptance Test

Flowbase: See Completion Guidebase.

HCR: High Collapse Resistance

HDM: Hydraulic Distribution Module

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



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HPU: Hydraulic Power Unit

Integral Valves: Valves machined from the single large block or forging that forms part of the subsea tree body, as opposed to bolt-on valves.

ISU: Integrated Service Umbilical

IWOC: Installation and Workover Controls.

JDT: Jumper Deployment Tool

LIM: Line Insulation Monitor

LMRP: 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.

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: 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.

MASCOT: Module and Surface Computer Operations Tester

MCS: Master Control Station

MMI: Man Machine Interface

Mono-Bore Tree: A subsea tree with the production bore passing vertically through the tree body and the annulus bore exiting through the side of the tree.

Mudline Conversion System: A system of equipment by which a mudline suspension system may be converted to accept a mudline tree.

Mudline Suspension System: A system for hanging casing at or below the mudline in offshore wells drilled using a surface BOP.

Mudline Tree: A subsea christmas tree designed for installation on a mudline wellhead.

Mudline Wellhead: A subsea wellhead used with a mudline suspension system.

OS: Operator Station

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

Permanent Guidebase (PGB): A fabricated steel structure attached to the low pressure housing for guiding equipment onto and into the wellhead by means of guideposts and guidewires to the surface.

PLEM: Pipeline End Manifold.

Production Casing: The final casing into which the production tubing is installed.

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

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



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

Production String: See Production Tubing.

Production Tubing: The tubing through which the production fluids are delivered from the reservoir to the production tree.

PVT: Pressure, Volume and Temperature

ROV: Remotely Operated Vehicle.

SCM : Subsea Control Module

SCMMB: SCM Mounting Base

SCMRT: Subsea Control Module Running Tool

SCSSV: Surface Controlled Sub-Surface Safety Valve

Seal Assembly: The annulus seal assembly. See Packoff.

SEM: Subsea Electronics Module

SFL: Steel Flying Lead

Side Valve Tree: See Horizontal 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.

Single-Bore Tree: A Dril-Quip mono-bore tree.

SIT: System Integration Test

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

TFL (Through Flowline): A specialized well workover system using special tools designed to be pumped through the production flowline and down the production tubing.



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Through-Bore Tree: A subsea tree with the production bore passing vertically through the tree body and the tubing hanger in the tree body.

Tree Connector: 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.

Tree Mandrel: 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.

Tree Running Tool: 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.

Tubing Hanger: 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.

Tubing Head: A term sometimes used for a wellhead with a tubing hanger but no casing hangers. See Mudline Wellhead.

Tubing Spool Adapter: 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.

TUTA: Topside Umbilical Termination Assembly

TUTB: Topside Umbilical Termination Box

UJB: Umbilical Junction Box

UPS: Uninterruptible Power Supply

USV: Upper Swab Valve

UTA: Umbilical Termination Assembly.

UTH: Umbilical Termination Head

VSE: Valve Signature Emulator

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

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



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2 SUBSEA PRODUCTION EQUIPMENT

2.1 Introduction

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

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.

Figure 2.1 - A Variety Of Field Development Options Exist as Subsea Technology Moves Into Deeper Waters.



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2.2 Subsea Wellheads

2.2.1 Functions of Subsea Wellheads

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

to support the subsea blowout preventer (BOP) and seal the well casing during drilling

to support and seal the subsea production tree

to support and seal the well casing.

to support and seal the production tubing hanger.

Figure 2.2 - A Typical BOP Stack Being Deployed



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The subsea wellhead together with the BOP or the production tree provides the means to safely contain reservoir pressure during oil and gas drilling and production operations. It rarely sees actual reservoir pressure but is rated to withstand this pressure in case of loss of well control during drilling or a breach of a primary pressure barrier during production. Standard API pressure ratings in use are 5,000 psi, 10,000 psi, 15,000 psi. and more recently 20,000 psi.

The subsea wellhead may also be designed to accommodate a surface tie back system to a surface completion on a TLP, spar or, more rarely, a fixed platform.

2.2.2 Types of Subsea Production Wellheads

The term subsea wellhead, for the sake of this discussion, describes a specific class of wellhead used in subsea drilling applications that require installing the BOP at the seabed. It is sometimes also referred to as a marine wellhead. Subsea wellheads are typically used for drilling wells from a floating drilling rig.

Another class of wellheads that is sometimes employed on subsea production systems is the mudline suspension system. The mudline suspension system relies on the use of a surface BOP during drilling, usually from a jackup type drilling rig.

Subsea wellhead designs have evolved along with advances in subsea drilling and well completion technology. Subsea wellheads generally come in one of the following sizes:

13-5/8 inch

16-3/4 inch

18-3/4 inch

21-1/4 inch

The size designates the nominal bore (I.D.) of the wellhead, in inches. The 18-3/4 inch subsea wellhead is currently the most common. Earlier subsea drilling systems used a two stack approach and relied on a low-pressure 21-1/4 inch BOP to start the well and a high pressure 13-5/8 inch BOP for finishing the well. With the development of the 18-3/4 inch x 10,000 psi (10M) BOP, the well could be drilled to final depth with one BOP and the 18-3/4 inch x 10M wellhead became the standard. Wellhead pressure ratings are trending higher, with 18-3/4 inch x 15M wellheads becoming the new standard, though manufacturers still offer 10M models. 18-3/4 inch x 15M BOPs are not as common, but the 15M wellheads are compatible with the 10M BOP connectors.

Traditionally Drill Ships have used 16- inch subsea wellhead systems. The advantage of the 16- 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- 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- inch) bores. Operators may adopt Slim Hole well technology that starts with 26-inch conductors.



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2.2.3 Wellhead Connector Profiles

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

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.

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 forall height measurements.

Wellhead Datum Wellhead

Profile

Internal Profile Datum

Wellhead Datum



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2.2.4 Tubing Spool Adapters

It is necessary that the wellhead connector on the BOP be compatible with the wellhead on the planned development well. Fortunately BOP wellhead connectors can be changed out relatively easily. Operators may therefore specify the wellhead type and profile of choice, taking into account compatibility with other existing wells or their preference for the well completion equipment. If an operator wishes to complete a well with a tree having a connector that is not compatible with the wellhead, a wellhead conversion can be installed. This wellhead conversion is called a tubing spool adapter, and consists of a forged spool piece having a connector matching the existing wellhead on the bottom and a profile matching that of the trees 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- inch high-pressure wellhead (housing) with 20 inch/18- 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- inch, 16- inch, 13-3/8 inch, 10- 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 pack-off designs used elastomer seals. Newer designs employ metal to metal seals. These are, in some cases, actually composite metal and elastomeric seals designed so that the elastomer



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provides an initial seal that, with deformation, causes the metal seal to be forced into place or energized. The elastomer serves as a back-up seal.

Most of the casing weight is suspended at the mud line by the wellhead. Some casing strings are anchored deeper in the well. Later when the production tubing is installed, it is suspended either in the wellhead or tubing hanger adapter spool or in the tree above. Each method transfer the loads back to the wellhead.

During well production thermal and pressure effects on the tubulars can reverse the hanger loads and push up against the wellhead. Therefore lock down of the hangers is recommended for production wells. Some Exploration wellheads do not apply the lockdown feature so as to facilitate dismantling and abandonment of the well and because this feature can sometimes be troublesome to install.

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.

Figure 2.4 - Typical 13-3/8 Casing Hanger



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2.2.6 Wellhead Guide Structures

2.2.6.1 Guideline Drilling and Completions

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

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

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.

Figure 2.5 - A Typical Temporary Guide Base

Figure 2.6 - A Temporary Guide Base Being Deployed by a Running Tool on Drill Pipe



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PGBs normally incorporate level indicators that can be observed by camera when landing the first conductor in a new well. If the conductor is off true vertical by more than about one degree, the driller may decide to re-spud the well. It is recommended almost universally to do this if the well is off vertical by more than one degree. If not, key seating (wearing on one side) of the casing and or BOP stack can occur seriously degrading the pressure integrity of the well and well control equipment.

The guideposts are normally designed to accommodate guide wires latched to the post tops. The post tops are generally designed to enable easy latching or unlatching of the guide wires and include a means of reestablishing new guide wires onto the post top. Virtually all PGBs utilize the API standard post spacing, four guideposts at 90 spacing, on a six-foot radius from the well center. This leads to the standard 101.82 inches between posts.

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.

Figure 2.7 - Example of a Retrievable Permanent Guide Base



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2.2.7 Loads on Wellheads

Wellheads must be designed for high structural loads imposed during drilling, workover, or well completion operations. The wellhead must support the weight of the BOP, drilling riser loads, casing weight and forces imposed by internal pressure. In general, wellheads are of such robust construction that, as far as external loads are concerned, they are rarely the weak point of the wellhead system. The 15M wellheads can generally sustain greater external loads than the 10M wellheads. For deep water and other special applications, manufacturers must engineer the wellhead equipment to meet the specified load requirements. A heavy duty deepwater wellhead with a heavy duty connector engaging two profiles instead of the one for more strength is shown in Figure 2-11.

To improve the transfer of loads from the wellhead to the low-pressure conductor housing and reduce fatigue stresses and fretting at critical wellhead interfaces, a rigid lockdown system may be employed. This mechanism locks the wellhead housing securely into the low-pressure 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.

COMPONENT MATERIAL

Low Pressure Conductor Housing AISI 8630 Modified.

Conductor Pipe API 5L X52

18 3/4 inch Wellhead Housing AISI 8630 Modified, 80 Ksi. Yield

Wellhead Seal Area Inconel 625 Overlay

20 inch Casing Extension, API 5L X52

Wellhead Lock Ring AISI 4140/4145, 105 Ksi. Yield

Casing Hangers AISI 8630 Modified, 80 Ksi. Yield

Pack-Off Seal Elements AISI 1010 or 1015

Pack-Off Bodies AISI 4140, 75 Ksi. Yield

Pack-Off Split Rings 17-4 PH, 100 Ksi. Yield

2.2.9 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 inch wellhead housing joint,

20 inch casing

13 3/8 inch and 9-5/8 inch centralized casing hangers

Associated packoffs.



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2.2.9.1 Subsea Wellhead Features:

The following are features that should generally be expected in wellhead equipment:

The ability to test all the seals and locking arrangements.

Protection for all permanent seals during running and the seals are remotely energized after landing.

The ability to clean component seal surfaces after cementing operations and prior to setting the pack off seals.

The casing hangers have ability to be locked in place.

The flow path for cuttings and cement returns without excessive build up of pressure, blockage or reduction in velocity through the flow-by holes and slots.

The use of a minimum number of seals and components installed subsea.

The primary metal-to-metal seals with elastomeric secondary system for all permanently installed seals.

Weld overlay surfaces with a nickel-based alloy (Inconel 625) at the wellhead's gasket seal surface.

Reliable and robust suite of versatile running tools.

2.2.9.2 30 inch Conductor Housing Joint.

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

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

Figure 2.8 - Typical 30 Wellhead Housing



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table while the running tool is made up to it. The padeyes are then cut or burnt off and the casing run to the seabed.

A 30-inch conductor housing should normally provide the following features:

An internal profile locking facility for the 30-inch conductor housing running tool.

Side outlet holes with diameters for cement returns.

Control of the elevation, concentricity, and vertical alignment of the 18-3/4-inch wellhead housing by the load shoulder and locking mechanism incorporated with the internal profile.

Unrestricted passage of a 26-inch drill bit.

Available working pressure of 2000 psi (135 bar).

2.2.9.3 18-3/4 inch Wellhead Housing Joint.

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

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 18-3/4 inch wellhead housing joint is approximately 40 feet.

Figure 2.9 - Typical 18-3/4 Wellhead Housing



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

Positive mechanical lockdown mechanism into the 30 inch conductor housing.

Provision for the flow of drill cuttings and cement returns between the 18-3/4 inch wellhead and the 30-inch conductor housing.

Control of the elevation and concentricity of the casing hangers and the tubing hanger.

Seal surfaces appropriate for the sealing systems associated with the test and running tools.

Transfer loads from the hangers and bending loads from the BOP and riser into the 30 inch conductor housing. This can be achieved by a two point socketing arrangement between the 30 inch housing and the 18- inch wellhead housing.

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 others profiles

Casing Hangers

Wear Bushing

Pack Offs or Seal Assemblies

Wellhead

Profile

Figure 2.10 - A Typical Modern Wellhead Stack-Up



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

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.

HC CONNECTOR ON DWHC HUB

DWHC Connector on Standard Hub

DWHC Connector on DWHC Hub

Figure 2.11 - One Manufacturers Standard (HC) and Deepwater (DWHC) Wellhead Connectors on Standard and Deepwater Wellhead Hubs, Demonstrating Their Interconnectability



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2.2.9.5 Pack-Off (Seal) Assembly.

The pack off or seal assembly should generally provide the following features:

The necessary seals and components to ensure that the seal is set, energized, tested and if required, retrieved in a single down hole trip.

Seals are protected during running phase.

Single trip tool runs casing hanger and pack off assembly as a unit.

Complete seal assembly can be retrieved using single trip tool or a pack off retrieval tool.

An effective seal for continuous or intermittent annulus pressure.

Bi-directional metal-to-metal seal with elastomeric backup seals to pack off the casing hanger to 18 3/4 inch wellhead housing annulus.

Suitable working pressure of 10,000 or 15,000 psi.

Figure 2.12 - Typical Casing Hangerfor Subsea Wellhead



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2.2.10 Wellhead Running Tools

Running tools are required to install, test and retrieve the wellhead system components. These tools are supplied by the wellhead manufacturer as part of the wellhead system, most often on a rental basis. One aspect of wellhead system design is to design the running sequence and tools so as to minimize the number of trips required. This becomes more important in deep water where rig rates are high and trips take more time.

The tools should be of robust design, debris tolerant, and capable of giving strong easily detected signals of correct function that can be observed at the drill floor.

Figure 2.13 - A Typical Suite of Subsea Wellhead Running Tools



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2.2.10.1 Bore Protector

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

2.2.10.2 Wear Bushing.

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

Figure 2.14 - A Typical 30 Wellhead Running Tool



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2.2.10.3 30-Inch Conductor Housing Running Tool.

The 30 inch running tool is used to deploy the 30 inch conductor string and housing. Typical features of this tool are:

Locks into the profile of the 30 inch housing.

Seals inside the 30 inch housing below the flow-by ports

Visual position indicator provided.

Anti-rotation feature.

Right hand rotation of the running string releases the tool. This is often a hydraulic function in deeper waters.

6 5/8 inch API Regular box up by 4 1/2 inch API Internally Flush (NC50) pin down.

Valves to allow filling of the string with seawater and then closed.

2.2.10.4 18 3/4 inch Housing Running Tool.

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

Locks into the upper groove inside the wellhead bore.

Has visual position indicator.

Right hand rotation of the running string to release. This is often a hydraulic function in deeper waters.

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.

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



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2.2.10.5 Bore Protector Running and Retrieval Tool.

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

2.2.10.6 Single-Trip Tool

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

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



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2.2.10.7 Pack-Off Assembly Running Tool

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

2.2.10.8 Drill Pipe Casing Hanger Running Tool.

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

2.2.10.9 Full Bore Casing Hanger Running Tool.

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

2.2.10.10 BOP Test Tool.

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

2.2.10.11 Emergency Drill Pipe Hang-Off Tool.

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

2.2.10.12 Mill and Flush Tool.

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

2.2.10.13 Emergency Seal Assembly.

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



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2.2.11 Typical Subsea Wellhead Installation Procedures

Run 30 inch conductor string into open hole with 30 inch suspension joint attached to the guidance cone.

Once landed and set to the correct vertical elevation, cement 30 inch conductor in place according to operator procedures.

Rotate the drill pipe and pull to release running tool. Pull back to surface.

Drill the next hole to TD and run the 20-inch casing.

Attach the 18 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 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 inch wellhead. Slack off the weight and cement the string into place. Activate the pack off setting mode of the tool

Slack off the string weight and close the BOP pipe rams.

Build up pressure above the tool to set and test the pack off. Open the pipe rams, release the tool from the pack off and then pull it back to the surface.

Run in the 13-3/8 inch bore protector on the bore protector running tool. Land and lock into the wellhead. Release the tool and pull back to the surface.

Repeat the above steps to run the next casing strings.

Start next functions for well (e.g. Temporary abandonment, permanent abandonment, completion, etc.).



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2.3 Subsea Christmas Trees

2.3.1 Functions of Subsea Trees

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

Sealing the wellhead from the environment by means of the tree connector.

Sealing the production bore and annulus from the environment.

Providing a controlled flow path from the production tubing, through the tree to the production flow line. Well flow control can be provided by means of tree valves and/or a tree-mounted choke.

Providing access to the well bore via tree caps and/or swab valves.

Providing access to the annulus for well control, pressure monitoring, gas lift, etc.

Providing a hydraulic interface for the down hole safety valve.

Providing an electrical interface for down hole instrumentation, electric submersible pumps, etc.

Providing structural support for flow line and control umbilical interface.

Figure 2.17 - Schematic Representations of Different Tree Types

Tree Tubing Head Spool Tubing Hanger Subsea Wellhead



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2.3.2 Types of Subsea Trees

2.3.2.1 Dual Bore Tree or Conventional Tree

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

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

Figure 2.18 - Example of a Compact Dual Bore Tree



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through the tubing hanger. This port, as well as the production bore, must be closed before removing the BOP or the subsea tree.

On a conventional style tree, the annulus port is typically sealed with a wire line plug run and retrieved through a multi-bore completion riser or a riser with a diverter mechanism. This riser is generally expensive and dedicated to the tree system. Refer to descriptions of riser systems elsewhere in this document for detailed descriptions.

In the mono bore tree system the tubing hanger is run on drill pipe or tubing and the annulus is accessed through a hose bundle. Opening and closing of the annulus is accomplished by means of a shiftable plug or valve in the annulus bore. The disadvantage to this, as compared to the dual bore system, is the requirement for moving parts within the tubing hanger that must be left subsea for the life of the completion.

Some designs incorporate a second plug or valve, ported in series with the primary plug, which can be actuated as a backup to close the annulus if more redundancy is desired.

The mono bore tree obviates the need for a true vertical annulus bore through the tree.

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

Figure 2.19 - Deepwater Guidelineless Horizontal Tree

Figure 2.20 - Monobore Tree



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name, are: 1) the tubing hanger is installed in the tree itself, rather than in the wellhead and 2) the top of the tree is designed so the BOP may be landed onto the tree. This arrangement allows the tubing string to be recovered without first retrieving the tree.

Horizontal Tree technology was conceived and developed to run and retrieve well bore tubing through an installed tree providing a simple and efficient work-over capability. Originally, this type of technology seemed ideally suited for Electric Submersible Pump (ESP) applications, where frequent pump maintenance or replacement may be required. Well interventions were most commonly caused by the need to repair downhole problems as opposed to subsea tree equipment problems.

The concept was extended to include standard production and injection wells in the belief that horizontal technology offered much greater benefit over conventional technology, at least in some applications.

The benefits and drawbacks of both horizontal and conventional tree technologies have been the subject of many debates for several years. The newer horizontal tree technology has been shown to have significant merit in order to have acquired at least 50 % of the market in less than six years. It is probable that both completion technologies will have a vital part to play in future oil and gas developments and the possibility of a winner for all applications is unlikely.

Figure 2.21 - Horizontal Trees



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2.3.2.4 ADVANTAGES of Horizontal Trees

Tubing recovery is simplified. The ability to perform tubing work-over and some drill-through 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 stacks 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 datums.

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.



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Subsea component building blocks can be arranged into many different tree layouts. This has given considerable flexibility to horizontal tree configuration and improved the opportunity of mass produced tree equipment by allowing the flexibility to manufacturers. Tree internals can be standardized while external characteristics can be varied or moved to suit the application.

A Horizontal subsea tree design, using guidelines, can be readily converted to a guideline-less and funnel-down, wellhead re-entry system. This is achieved by adding a bolt-on funnel to the bottom of the tree. A funnel-down, BOP stack, wellhead re-entry system can be used for guideline-less re-entry to a Horizontal Tree with little or no change to the standard guideline subsea tree. This will provide the lightest possible guideline-less subsea tree weight.

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



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2.3.2.5 DISADVANTAGES of Horizontal Trees

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

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 work-over 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.

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



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

The tubing hanger hydraulic and electrical penetrations exit through the side of the subsea trees 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

ROVs 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.

Figure 2.24 - Dual Bore Tree Being Deployed



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2.3.2.6 ADVANTAGES of Conventional Dual And Mono Bore Trees

Only one BOP trip is required in a drill-and-complete scenario. In addition, no temporary well abandonment plug is required between the BOP stack recovery and the tree installation as the tubing hanger serves that purpose.

The subsea tree can be recovered without having to recover the tubing hanger and down-hole completion because the tubing hanger lands in the wellhead and not in the subsea tree.

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.

Figure 2.25 - Dual Bore Guidelineless Tree on Test Stand



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

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 hangers 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.

Figure 2.26 - Horizontal Tree With Trawl Protector Frame



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2.3.2.8 Other Types of Trees

There are other specialized variations of subsea trees as well. These include TFL trees designed for use with special through flowline (TFL) workover equipment; Single-Bore or mono-bore t