JIP FPS Mooring Integrity Rr444

HSEHealth & Safety

Executive

Floating production system

JIP FPS mooring integrity

Prepared by Noble Denton Europe Limitedfor the Health and Safety Executive 2006

RESEARCH REPORT 444

© Crown copyright 2006

First published 2006

All rights reserved. No part of this publication may bereproduced, stored in a retrieval system, or transmitted inany form or by any means (electronic, mechanical,photocopying, recording or otherwise) without the priorwritten permission of the copyright owner.

Applications for reproduction should be made in writing to:Licensing Division, Her Majesty's Stationery Office, St Clements House, 2-16 Colegate, Norwich NR3 1BQ or by e-mail to [email protected]

HSEHealth & Safety

Executive

Floating production system

JIP FPS mooring integrity

Noble Denton Europe Limited No 1 The Exchange

62 Market StreetAberdeen

AB11 5PJ

The main objective of this report is to improve the integrity of the mooring systems on Floating ProductionSystems (FPSs). It is intended to be read and understood by non mooring specialists such as FPSOperational staff - so that the people who live and work on FPSs will be better able to become moreinvolved in the vital task of looking after their own mooring systems. Meanwhile the included feedback onthe actual performance of mooring systems in the field should assist designers and manufacturers toimprove future mooring designs. Hence, the report attempts to identify gaps in the existing knowledge ofmooring behaviour and components to provide a road map for future work. Appendix C includes a paperpresented at the 2005 Offshore Technology Conference (OTC) which represents a stand alone summaryof the key points of the JIP.

This report and the work it describes were funded by the Health and Safety Executive (HSE). Its contents,including any opinions and/or conclusions expressed, are those of the authors alone and do notnecessarily reflect HSE policy.

HSE BOOKS

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CONTENTS

SECTION PAGE NO.

1 EXECUTIVE SUMMARY 11

2 INTRODUCTION AND SCOPE 17

3 MOORINGS OVERVIEW 22

3.1 Mooring Basics 223.2 Mooring Line Constituents 393.3 Determination of Minimum Break Load (MBL) & Maximum Stresses 58

4 CONTEXT SETTING - HISTORICAL INCIDENTS AND THEIR

SIGNIFICANCE 65

4.1 Long-Term Degradation Mechanisms 654.2 Multiple Line Failure Incidents 744.3 “Petrojarl 1” Multiple Lines Failure (1994) 76

5 CONSEQUENCES OF MOORING LINE FAILURE 77

5.1 Single Line Failure 775.2 Multiple Line Failure 795.3 Danger of Hydrocarbon Release 815.4 Business Interruption Consequences - Two Case Studies 82

6 HANDLING, TRANSPORTATION/TRANSFER AND INSTALLATION 85

6.1 Transportation/Transfer 856.2 Installation of Mooring Lines and Connectors 866.3 Installation Watch Points from a Mooring Integrity Standpoint 93

7 CORROSION, FATIGUE AND WEAR (CASE STUDIES) 99

7.1 The “Balmoral FPV” – An Industry Benchmark 997.2 Corrosion and Wear Allowance – Discussion of Code Requirements 1017.3 North Sea FPSO – Apparent Corrosion and Wear Data 1087.4 Sulphate Reducing Bacteria (SRB) Induced Pitting Corrosion 1127.5 Stress Corrosion Fatigue 1137.6 Wear Analysis (Shoup and Mueller Work) 118

8 UNBALANCED LINE PRE-TENSIONS (CASE STUDIES) 122

8.1 North Sea Semi-Submersible FPS 1228.2 Line Payout/Pull-In Test 1238.3 North Sea FPSO 124

9 MOORING BEHAVIOUR AT THE VESSEL INTERFACE (CASE STUDIES) 126

9.1 Permanently Stoppered Off Versus Adjustable Lines 1269.2 Wear at Trumpet Welds – Internal and External Turrets 1309.3 Use of Bending Shoes 143

10 FURTHER MOORING CASE STUDIES 145

10.1 Wire Rope Systems 14510.2 Unintended Line Disconnection 14610.3 Excursion Limiting Weighted Chain Problems 15110.4 Line Run Outs and Quick Releases 15510.5 Windlass Failures 158

11 SPARS AND OFFLOADING BUOYS (CASE STUDIES) 160

11.1 Brent Spar Buoy 16011.2 Floating Loading Platform (FLP) 163

12 TURRET MECHANICAL IMPLICATIONS FOR MOORING INTEGRITY 165

12.1 Introduction to Turrets and Failure Modes 165

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12.2 Implications of Mechanical Repairs 168

13 GENERAL TRENDS AND STATISTICS 169

13.1 Questionnaire Process 16913.2 Summary Statistics for Unit Type and Geographical Area 17113.3 HSE UK Sector and Norwegian Statistics 174

14 CONNECTORS AND TERMINATIONS 177

14.1 Background 17714.2 What Type of Connectors Can be Considered for Long Term Mooring (LTM) 17714.3 Terminations General 18214.4 Connector/Termination Design Flow Chart 18614.5 Detailed Design Guidance 18914.6 Proof Load Testing and Its Impact on Fatigue 193

15 OUT OF PLANE BENDING – CHAIN AND ROPES (FIBRE + WIRE) 197

15.1 Tension Bending at a Wildcat and its Effect on Fatigue 19715.2 Tension Bending at Chainhawse 20515.3 Tension Bending In Wire Rope 21515.4 General Implications of Tension Bending Fatigue for the FPS Industry 21915.5 Recommendations 222

16 FRACTURE MECHANICS AND CRITICAL CRACK SIZE 223

16.1 Required Data 22316.2 Fracture Mechanics and Chains – State of the Art Summary 22416.3 Fracture Mechanics Critical Crack Size Implications 225

17 LINE STATUS MONITORING AND FAILURE DETECTION 226

17.1 Instrumentation Status - Survey Results 22617.2 Existing Failure Detection Systems 22717.3 Future Failure Detection Systems 232

18 INSPECTION, REPAIR & MAINTENANCE (IRM) 238

18.1 In Air-Inspection 23818.2 Where to Inspect on a Mooring Line 23918.3 In-Water Inspection 24218.4 Marine Growth Removal 24618.5 Manufacturing Tolerances and the Inspection Implications 24718.6 Wildcat/Gypsywheel Inspection 24718.7 Inspection Frequency – Code Requirements 25518.8 Outline Method To Break Test Worn Mooring Components 257

19 SPARING OPTIONS 261

19.1 Contingency Planning - Spares and Procedures 261

20 THE IMPORTANCE OF A COMPREHENSIVE MOORING DESIGN

SPECIFICATION 264

20.1 Installation Parameters 265

21 KEY CONCLUSIONS & FUTURE WORK RECOMMENDATIONS 267

21.1 Overview 26721.2 Key Conclusions 26821.3 Recommendations for Further Study 270

22 REFERENCES AND BIBLIOGRAPHY 272

23 APPENDIX A - SUMMARY OF PAST RELEVANT JIPS 278

24 APPENDIX B – MOORING INTEGRITY QUESTIONNAIRE (EXCEL) 279

25 APPENDIX C – 2005 OTC JIP PAPER 280

26 APPENDIX D – HSE SAFETY NOTICE 3.2005 FLOATING PRODUCTION

AND OFFLOADING (FPSO) MOORING INSPECTION 281

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LIST OF TABLES

Table 1-1 - North Sea Mooring Line Failure Data, 1980 to 2001 [Ref. 1] ...................................12 Table 1-2 - Indicative Single Mooring Line Failure Costs ...........................................................13 Table 3-1 – Summary of Chain Design Parameters (modified from Vicinay Chain Catalogue)..41 Table 3-2 – Comparison of Manufacturing Parameters ................................................................41 Table 3-3 – Chain Geometry Implications for Inspection and Maintenance ................................42 Table 3-4 - Summary of Ship or Marine Grade Chains [Ref. 13].................................................45 Table 3-5 – Example of Indicative Surface Hardness Values for Various Chain Grades (courtesy

of Vicinay).............................................................................................................................46 Table 3-6 – Illustration of Indicative Wire Rope Material Properties [Ref. 2] .............................49 Table 3-7 - Comparison of the Advantages of Spiral and Six Strand Wire (courtesy of Bridon) 50 Table 3-8 - Comparison of the Cons of Spiral and Six Strand Rope ............................................50 Table 3-9 - Wire Rope Recommendations for Varying Field Lives (courtesy of Bridon) ...........50 Table 3-10 - Stipulated MBL and Proof Load Values for Various Sizes and Grades of Chain

(courtesy of Vicinay).............................................................................................................62 Table 5-1 - Line Failure Cost Estimate, 50,00bpd North Sea FPSO ............................................83 Table 5-2 - Line failure Cost Estimate, 250,000bpd West African FPSO ....................................84 Table 7-1 - Example of Specified Corrosion and Wear Allowances from One Classification

Society.................................................................................................................................102 Table 12-1 - Summary of the Pros and Cons of Sliding and Roller Bearings [Ref. 48] .............167 Table 13-1 - Example of the First Page of the Questionnaire – see appendix B for a Full Listing

.............................................................................................................................................169 Table 13-2 - UK Sector of the North Sea Data [Ref. 49]..........................................................174 Table 13-3 - UK Sector of the North Sea Data [Ref. 49]...........................................................174 Table 13-4 – Number of Anchor Incidents in the Period of 1990-2003 in the Norwegian Sector

[Ref. 50] ..............................................................................................................................174 Table 15-1 – Comparison between Chain Tension-Bending Fatigue Parameters Note that values

in italics are derived from BOMEL measured stress factor. ...............................................203 Table 15-2 : Wire Rope Fatigue Reduction Due to Tension Bending [Ref. 31].........................216 Table 15-3 - S-N Parameters for Mooring Chain Fatigue..........................................................220

LIST OF FIGURES

Figure 1-1 - Red Arrows Indicate Key Areas subject to Degradation on a ..................................14 Figure 2-1 - JIP Organisation ........................................................................................................19 Figure 2-2 - CTR Breakdown........................................................................................................19 Figure 2-3 – Participants at the Steering Committee meeting in Paris .........................................21 Figure 3-1 – Typical Turret Moored FPSO...................................................................................22 Figure 3-2 – Shallow and Steep Mooring Line Angle Illustration................................................23 Figure 3-3 – Line Heading Illustration..........................................................................................23 Figure 3-4 – Definition of Windward and Leeward Lines + Environmental Offset.....................24 Figure 3-5 – Offset Position and Tension Effect...........................................................................25 Figure 3-6 – Illustration of Load Excursion Curve [Ref. 2]..........................................................25 Figure 3-7 - Typical Spread Moored Unit, Girassol FPSO offshore West Africa (courtesy of Stolt

Offshore) ...............................................................................................................................26 Figure 3-8 – Illustration of Catenary System................................................................................28 Figure 3-9 - Typical Spread Moored Catenary System (Courtesy of Vryhof) .............................28 Figure 3-10 – Illustration of Taut-Leg system ..............................................................................29 Figure 3-11 - Typical Spread Moored Taut-Leg System (Vryhof)...............................................29

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Figure 3-12 – Illustration of Surge, Sway, Heave, Roll, Pitch and Yaw ......................................30 Figure 3-13 – Example of Optimising the Stiffness of the Load offset Curve ............................32 Figure 3-14 - Illustration of Long Crested (Unidirectional) Seas .................................................35 Figure 3-15 - Illustration of Short Crested (Confused) Seas.......................................................35 Figure 3-16 - Example of a Wave Breaking on a Column of a Semi-Submersible ......................36 Figure 3-17 - Illustration of Deepwater Breaking Wave Types (Plunging Break on the Left and

Spilling Breaking on the Right) ............................................................................................37 Figure 3-18 - Illustration of the Damage Caused to Schiehallion’s Bow by an Unusually Steep

Wave (courtesy of BP) ..........................................................................................................37Figure 3-19 - Model Illustration of the Effect of a Breaking Wave on a FPSO (Courtesy of APL

website) .................................................................................................................................38 Figure 3-20 - Isambard Kingdom Brunel in front of Studded Chain for the “Great Eastern” steam

ship, circa 1858 .....................................................................................................................39 Figure 3-21 – Comparison of the Geometry of Modern Studded and Studless Chain..................40 Figure 3-22 - “SPATE” Contour Map of a 76mm Loose Stud Chain Link [Ref. 8].....................43 Figure 3-23 - Example of the Arrangement of an Asymmetric Stud ............................................44 Figure 3-24 – Indication of the Manufacturing Tolerances of Studless Links (courtesy of

Vicinay).................................................................................................................................47 Figure 3-25 – Studlink Manufacturing Tolerances (courtesy of Vicinay) ....................................48 Figure 3-26 - Illustration of the Make Up of Different Wire Rope Types (courtesy of Bridon) ..49 Figure 3-27 – Chronology of Deep Star Funded Synthetic Mooring Studies –............................51 Figure 3-28 - Accurate Drag Anchor Placement by Crane in Good Weather Conditions (courtesy

of Stolt Offshore) ..................................................................................................................52 Figure 3-29 Installation and Normal (Vertical) Load Position (courtesy of Vryhof ) .................53 Figure 3-30 Anchor Pile + Chain Tail Deployed by a Twin Crane Construction Vessel (courtesy

of Stolt Offshore) ..................................................................................................................53 Figure 3-31 Suction Anchor Deployment (courtesy of Stolt Offshore).......................................54 Figure 3-32 - Example of a Tensile Test on a Steel Sample cut out from a Chain Link .............58 Figure 3-33 - Example of a Chain Sectioned for Material Testing..............................................59 Figure 3-34 - Example of Terminology during a Tensile Test (courtesy of Ashby & Jones, [Ref.

17]) ........................................................................................................................................59 Figure 3-35 - Stress Strain Curves for R3, R4 and R5 Chain Steel (Data courtesy of Vicinay)..61 Figure 3-36 – Approximation of the Stress Distribution in a Typical Chain Link .......................63 Figure 3-37 - Illustration of a Finite Element Representation of a Chain Link ............................64 Figure 3-38 – Finite Element Representation of a Shackle Body .................................................64 Figure 4-1 – Illustration of some of the Main Factors which Influence Mooring Integrity..........65 Figure 4-2 - “North Sea Pioneer” on the Argyll Field .................................................................66 Figure 4-3 – Fulmar SALM after Breakaway (courtesy of BBC film clip) ..................................68 Figure 4-4 – Schematic of the layout of the Fulmar SALM .........................................................69 Figure 4-5 - Extract from “On this Day” BBC Website ...............................................................70 Figure 4-6 – Illustration of a Typical Lightship Weathervaning Mooring ...................................71 Figure 4-7 - Helicopter Rescue from the Free Drifting “North Carr” Lightship after Mooring

Failure [Ref. 20] ....................................................................................................................72 Figure 4-8 - Illustration of the North Carr Link Failure Relative to a 1999 North Sea FPSO Link

Failure (fatigue cracking followed by ductile rip out) ..........................................................73 Figure 4-9 - Dutch Lightship Number 11 whose Mooring Failed in a Force 10 Gale in October

1991 which also broke a number of semi-sub moorings – see Section 4.2...........................73 Figure 4-10 - Fifth Generation “Deepwater Nautilus” Broke free of all her Moorings during

Hurricane Ivan.......................................................................................................................75 Figure 4-11 - “Petrojarl 1” which experienced two broken lines at the same time when hit by a

steep wave .............................................................................................................................76 Figure 5-1 - Summary of a Single Line Failure Scenario .............................................................78

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Figure 5-2 – Illustration of Riser “Stretch” After Loss of Position Following Mooring Line Failure....................................................................................................................................79

Figure 5-3 - Potential Multiple Line Failure Scenario ..................................................................80 Figure 5-4 - Example of how Mooring Integrity Philosophy can affect Production ....................81 Figure 6-1 - Spooling Fibre rope onto a Powered Reel from Standard Containers ......................85 Figure 6-2 - Illustration of the Weight and Handling Issues Associated with Mooring

Components (Courtesy of Stolt Offshore) ............................................................................86 Figure 6-3 - Red Arrows Show Examples of Mooring “Dog-Legs”.............................................87 Figure 6-4 - Illustration of Twist on a FPSO Mooring Line during Recovery ............................90 Figure 6-5 – Illustration of a “Hockle” in Spiral Strand Wire during Recovery of a FPSO

Mooring System ....................................................................................................................90 Figure 6-6 - Example of Damage to the Bend Stiffener on an Open Socket ................................91 Figure 6-7 – Illustration of Spiral Strand Wire Kinking during Installation.................................91 Figure 6-8 - Mid Line Buoy Swivel Connection Link (courtesy of MoorLink AB). ...................92 Figure 6-9 – Pre-Stretching Polyester lines During Installation to Minimise the Requirement for

Future Line Length Adjustments [Ref. 27] ...........................................................................96 Figure 6-10 - Illustration of the Potential Difficulty in offshore alignment of pins on large

Diameter Rope [Ref. 26] .......................................................................................................97Figure 6-11 - Sledge used to Protect “H” Connector during Deployment over the Stern Roller

(Courtesy I. Williams)...........................................................................................................97 Figure 7-1 –The Balmoral Benchmark FPV which has been continuously on station since 1986

(Courtesy of CNR) ................................................................................................................99 Figure 7-2 – Plan View of Mooring Incidents at Balmoral........................................................100 Figure 7-3 Illustration of the Extent of General Corrosion on a Recovered Floating Production

Unit Mooring Line after 16 years service ...........................................................................103 Figure 7-4 Illustration of the Extent of Corrosion Pitting..........................................................104 Figure 7-5 – Example of the Damage Caused to the Crown of the Links ..................................105 Figure 7-6 – Arrow shows the Apparent Grinding Action on the Inner Face of One of the Links

.............................................................................................................................................105 Figure 7-7 – Example of the Damage Caused to a Hanging Shackle Pin on a FPSO Mooring Line

.............................................................................................................................................106 Figure 7-8 Finite Element Stress Contour Plot (compare red areas with Figure 7-6) [Ref. 8] ..106 Figure 7-9 - Example of Thrash Zone Wear ..............................................................................107 Figure 7-10 - Illustration of the Extent of Pitting Corrosion......................................................108 Figure 7-11 - Example of Wear and Pitting Corrosion on the Shackle Pin ...............................109 Figure 7-12 -Test Rig Set Up for Break Testing of Mooring Components (Studless Chain in the

instance) ..............................................................................................................................111 Figure 7-13 – Illustration of Biologically Induced Pitting Corrosion in a Ballast Tank.............112 Figure 7-14 - Crack Growth per Cycle versus Stress Intensity Range [Ref. 2] ..........................113 Figure 7-15 – Illustration of Excessive Chain Wear on a CALM Buoy [Ref. 34]......................115 Figure 7-16 – Typical Temperature and Salinity Profile in the Tropical Oceans .......................116 Figure 7-17 – Indicative Oxygen Concentration versus Water Depth (courtesy of BP).............116 Figure 7-18 – Gulf of Mexico Snap Shot of Bottom Oxygen Concentration .............................117 Figure 7-19 - Measured Wear Rates of U3 and U4 Chain at 8,170lbs (300 tonnes equivalent)

[Ref. 34] ..............................................................................................................................119 Figure 8-1 – Illustration of Line Tension Variations during a Payout/Pull-In Test....................123 Figure 9-1 - Turret Design in which Chain Lengths can be Adjusted (courtesy of Chevron-

Texaco)................................................................................................................................127 Figure 9-2 – Generic Turret Design in which the Chains are Stoppered off at the Turret Base

(courtesy of Bluewater) .......................................................................................................127Figure 9-3 - Spread Moored FPSO Single Axis Chain Stopper (courtesy of SBM)...................128

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Figure 9-4 - External Cantilever Turret which experienced Chain wear at the Trumpet Welds which was halted by use of UMPHE (courtesy of Shell)....................................................130

Figure 9-5 - Example of the Level of Inspection Detail which can be achieved using a Typical Workclass ROV (courtesy of I.Williams) ...........................................................................131

Figure 9-6- Test Tank Mock-Up of Micro-ROV inspection of Chain Emerging from Turret “Trumpet” (courtesy of I. Williams) ...................................................................................132

Figure 9-7 - Micro-ROV Photograph of Chain Wear Notches where Chain Emerges at the Trumpet Bell Mouth (courtesy of I. Williams) ...................................................................132

Figure 9-8 - Indication of the Extent of the Wear ......................................................................133 Figure 9-9 - Artificially Introduced Notch on to Spare Chain Links, note also Red Circular

Infrared Target (courtesy of I. Williams) ............................................................................134 Figure 9-10 - Example of Stretched Chain during Break Testing, the Blue Mark Shows the

Location of a Typical Notch (courtesy of I. Williams) .......................................................134 Figure 9-11 - Example of a Special Cobalt Chromium Anti-Wear Coating (courtesy of I.

Williams).............................................................................................................................135 Figure 9-12 - Photograph of a Recovered Link Showing a Wear Notch (courtesy of I. Williams)

.............................................................................................................................................136 Figure 9-13 - An Example of the Chain Damage noted after the Notched Chains had been

recovered back to Shore (courtesy of I. Williams)..............................................................136 Figure 9-14 - Turret Arrangement where the Chain Stopper (in red) is Behind the Rotation Point

(2 black concentric circles) .................................................................................................137Figure 9-15 – Illustration of Potential Wear at Metal to Metal Contact (courtesy of I. Williams)

.............................................................................................................................................138 Figure 9-16 - Fairlead Chain Stopper where the Chain Stopper is in Front of the Rotation Point

(used on some Spread Moored FPSOs) (courtesy of Maritime Pusnes) .............................138 Figure 9-17 - As Installed Photo Graph of the Design Shown in Figure 9-16 (courtesy of

Maritime Pusnes).................................................................................................................139 Figure 9-18 – Typical CALM Buoy Chain Stopper (courtesy of “The Professional Diver’s

Handbook” [Ref. 38])..........................................................................................................140Figure 9-19 - Amoco CALM Buoy- Note Inclusion of Rubber Casting (courtesy of [Ref. 38])140 Figure 9-20 - Comparison of Alternative Fairlead Arrangements (courtesy of Bardex) ...........142 Figure 9-21 – Example of a Wire Rope Bending Shoe (courtesy of API RP25K) .....................143 Figure 9-22 - Example of a Chain Bending Shoe Design [Ref. 39]............................................143 Figure 9-23 - Bending Shoe Design which includes an Angle Sensor [Ref. 40]........................144 Figure 10-1 – Examples of the Subjectivity Associated with Assessing IWRC Rope Conditions

[Ref. 43] ..............................................................................................................................145 Figure 10-2 - Illustration of the Mooring Layout and Connections............................................146 Figure 10-3 - Photograph of Disconnected Socket on the Sea-Bed (courtesy of BP/Stolt

Offshore) .............................................................................................................................147 Figure 10-4 - Note End Plate also seems to be Falling Off on the Right Hand Side (courtesy of

BP/Stolt Offshore)...............................................................................................................147 Figure 10-5 - End Connection Detail .........................................................................................148Figure 10-6 - Illustration of Socket Minus End Plate .................................................................148 Figure 10-7 - Repair Utilised Bigger Bolts and Allowed the Socket Pin to Rotate ....................149 Figure 10-8 - Example of Retrofitted Anodes to Control Corrosion Rate ..................................150 Figure 10-9 - Example of Disconnected Anodes after approximately 12 months of Service.....150 Figure 10-10 - Example of Detached Clump Weight on the Sea-Bed ........................................151 Figure 10-11 - Example of Recovered Clump Weights ..............................................................151 Figure 10-12 – Illustration of Where the Damage Occurred on the Mooring Catenary .............152 Figure 10-13 - Example of a Parallel Chain Excursion Limiter (courtesy of I. Williams) .........152 Figure 10-14 - Weighted Chain Option Utilising Parallel Chain Sections (courtesy of

N.Groves) ............................................................................................................................153

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Figure 10-15 - Red Arrow Illustrates the Local Wear can take place when utilising Parallel Chain (courtesy of N. Groves) ............................................................................................153

Figure 10-16 - Example of Mid-Line Buoy Failures on a European FPSO................................154 Figure 10-17 - Gripper chock showing chain damage ................................................................156 Figure 10-18 - Upper Gypsy Wheel Arrangement before Failure ..............................................156 Figure 10-19 - Gypsy wheel structure after failure, i.e. Gypsy Wheel No Longer Present ........156 Figure 10-20 - Illustration of a New Design of Kenter Shackle intended to have improved

Fatigue Performance ...........................................................................................................157Figure 10-21 - Example of Windlass Crack (Red Arrow) due to Stress Raiser caused by Sharp

Corner (courtesy of BP) ......................................................................................................158Figure 11-1 - General Arrangement of the Brent Spar Mooring System (courtesy of Shell) .....160 Figure 11-2 - Brent Spar Fairlead Chain Stopper in the Hull (courtesy of Shell).......................161 Figure 11-3 - Close Up of the Stopper (courtesy of Shell) .........................................................161 Figure 11-4 - Indentation from where the chain bore down on the Stopper (courtesy of Shell) 162 Figure 11-5 – Red Arrow Illustrates wear on the chain, where it sat on the stopper (courtesy of

Shell) ...................................................................................................................................162 Figure 11-6 - Brent Spar Wire Sample Y1 prior to cleaning [Ref. 41].......................................163 Figure 11-7 – FLP Mooring General Arrangement (courtesy of Shell)......................................163 Figure 11-8 - Example of Short Trumpets on a Long Term Moored Floating Loading Platform

(courtesy of Shell) ...............................................................................................................164 Figure 13-1 - Comparison of Mooring Line Inspection Periods for Different FPS Categories.173 Figure 13-2 – Historical Failure Rates for Different Types of Units .........................................176 Figure 14-1 - Special Joining Shackle (courtesy of Vicinay Catalogue) ....................................179 Figure 14-2 - “H” Shackle Pin Configuration (courtesy of I. Williams) ....................................180 Figure 14-3 – Illustration of Subsea Connectors which have been used on Pre-Installed Mooring

Lines ....................................................................................................................................181 Figure 14-4 - Example of a Special Joining Plate - Note Electrical Isolating Bush ...................181 Figure 14-5 – Example of the Make Up of a Typical Closed Spelter Socket (courtesy of Bridon)

.............................................................................................................................................182 Figure 14-6 - Example of an Open Socket ..................................................................................183 Figure 14-7 - Example of a Closed Socket .................................................................................183 Figure 14-8 - Connector or Termination Design Flow Diagram - Initial Phase ........................187 Figure 14-9 - Connector (Termination) Detailed Design Flow Chart.......................................188 Figure 14-10 – Illustration of a Purpose Designed connector allowing limited compliance in Two

Planes ..................................................................................................................................190 Figure 14-11 - Example of a Dynamic Analysis to Estimate the Angle for the “V” Slot Size on

the “H” Shackle...................................................................................................................191 Figure 14-12 - Example of Material with a Non Clearly Defined Yield Point ..........................194 Figure 15-1 Broken Link from Fairlead.....................................................................................197

Figure 15-2 Mechanical Damage on Fairlead Link................................................................... 197Figure 15-3 - Support of a Link in a Wheel Fairlead .................................................................198 Figure 15-4 - Photograph of Test Link Showing Bearing Plates [Ref. 10]................................. 199Figure 15-5 - General View of Tension Bending Test Rig (protective screens removed for

clarity) [Ref. 10]................................................................................................................. 199Figure 15-6 - Broken Hardened Plates at the end of the First Test [Ref. 10] .............................200 Figure 15-7 - Twisted Link Due to Mis-aligned Butt Weld [Ref. 10] ........................................201 Figure 15-8 - Simple Out of Flatness Twist Measurement Jig [Ref. 10] ....................................201 Figure 15-9 - Illustration of Failed Link Due to Tension Bending [Ref. 10]..............................204 Figure 15-10 - Girassol Offloading Buoy [Ref. 55]...................................................................205 Figure 15-11 - Girassol Offloading Buoy – Failure in Chain Link 5 [Ref. 55] .........................206 Figure 15-12 - Girassol Offloading Buoy – Failure in Polyester Rope [Ref. 55] ......................206 Figure 15-13 - Chainhawser Arrangement and Location of Critical Link [Ref. 55] .................207

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Figure 15-14 - Out of Plane Bending Mechanism (See Section 25 – [Ref. 56].........................208 Figure 15-15 - Schematic of SBM Test Rig [Ref. 55] ...............................................................209 Figure 15-16 - Photograph of SBM’s Test Rig [Ref. 55]............................................................210 Figure 15-17 - Typical FPSO Chain Stopper Arrangement ........................................................211 Figure 15-18 – Illustration of Wire Rope Failure Modes (courtesy of Bridon)..........................217 Figure 15-19 - The 1.0MN Wire Rope Bending-Tension Fatigue Test Machine .......................218 Figure 15-20 - Tension Bending at Wheel Fairlead (Bearing Load Eccentricity) and Tension

Bending from Interlink Friction (Torque at Contact)..........................................................219 Figure 15-21 - Comparison between Various Mooring Chain S-N Curves...............................221 Figure 17-1 - Sonar Fish for Deployment through Turret (courtesy Chevron Texaco) .............227 Figure 17-2 – Sonar Fish Deployment Method (courtesy Chevron Texaco)..............................227 Figure 17-3 - Sonar Display Screen Showing 12 Mooring Lines and 2 Risers Close to the Centre

(courtesty Chevron Texaco) ................................................................................................228 Figure 17-4 - Simple Pre-Installed Inclinometer with + or – 1 Degree Accuracy ......................229 Figure 17-5 - Illustration of a “Football” Sized ROV (Courtesy of I. Williams) .......................229 Figure 17-6 - Instrumented Load Pin – Shackle Link (courtesy of BMT/SMS).........................230 Figure 17-7 - Indication of the Data Available from Instrumented Mooring Lines (courtesy of

BMT/SMS)..........................................................................................................................231 Figure 17-8 - Illustration of a New Sonar System due to be Installed in the North Seas (courtesy

of I. Williams) .....................................................................................................................233 Figure 17-9 - Close Up of the Proposed Sonar Head (courtesy of Ian Williams)......................233 Figure 17-10 - Response Learning Without Line Tension Input ................................................234 Figure 17-11 - Illustration of Riser Monitoring Instrumentation (courtesy of 2H) ....................236 Figure 18-1 - Red Arrows and Black Line Indicate Key Areas subject to Degradation on a

Mooring System (leeward likely to have worst wear) ........................................................239 Figure 18-2 - Example of a Weight Discontinuity which may Result In Enhanced Wear .........240 Figure 18-3 - Typical Turret Cross Section Illustrating that the key Mooring Components are

Submerged...........................................................................................................................241 Figure 18-4 - Chain Stopper View Prior to Chain Installation with Pull in Rigging Present

(compare to Figure 18-3).....................................................................................................242Figure 18-5 - Illustration of ROV Deployed ‘Optical Calliper’ Measurement System (courtesy

of Welaptega Marine Ltd) ...................................................................................................244 Figure 18-6 – Illustration of Heavy Marine Growth on Long Term Deployed Chain...............246 Figure 18-7 - In-Situ Inspection of a Wildcat Pocket by Abseillers ..........................................248 Figure 18-8 - Close Up Of Fairlead Pocket – Note Slight Lip on the Right ...............................248 Figure 18-9 - Example of Chain Wear From Sitting in a Wildcat Pocket ..................................249 Figure 18-10 - Red Zones Highlight the Importance of Checking all Relevant Structural

Connections (Courtesy of CNR) .........................................................................................249 Figure 18-11 - Example of a Parted Lubrication Line Feeding a Submerged Wildcat or Gypsy

Wheel (Courtesy of CNR)...................................................................................................250 Figure 18-12 - Example of a Non Flat Link................................................................................251 Figure 18-13 - Buchan FPS Wire Rope NDT Inspection Head .................................................252 Figure 18-14 - Proposed Wire Rope Inspection Toll Delpoyed from a ROV............................253 Figure 18-15 - Example of a Difficult Area to Inspect ..............................................................256 Figure 18-16 - Partially Buried Shackle Illustrates the Difficulties in checking locking pins

(courtesy of ENI).................................................................................................................256 Figure 18-17 - Example of the Wheel Tappers Approach Used for Detecting Cracks on Railway

Carriages and Locomotives.................................................................................................258 Figure 18-18 - Example of Anchor Handling and Heading Control Tugs during a Mooring Line

Repair Operation (courtesy of I. Williams)........................................................................259 Figure 18-19 - Use of Divers from a RIB to open up the Chain Stopper during a FPSO Mooring

Line Repair (coutesy of I. Williams)...................................................................................260

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Figure 19-1 - Example of a Plate Shackle which may be useful for a Temporary Repair (courtesy of Balmoral Marine)............................................................................................................262

Figure 19-2 - Temporary Mooring Line Winch Deck on a Gulf of Mexico Spar.......................263

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1 EXECUTIVE SUMMARY

1.1 Overview of the Report

The main objective of this report is to improve the integrity of the mooring systems on Floating Production Systems (FPSs). It is intended to be read and understood by non mooring specialists such as FPS Operational staff - so that the people who live and work on FPSs will be better able to become more involved in the vital task of looking after their own mooring systems. Meanwhile the included feedback on the actual performance of mooring systems in the field should assist designers and manufacturers to improve future mooring designs. Hence, the report attempts to identify gaps in the existing knowledge of mooring behaviour and components to provide a road map for future work. Appendix C includes a paper presented at the 2005 Offshore Technology Conference (OTC) which represents a stand alone summary of the key points of the JIP.

1.2 Introduction

Unlike trading ships, FPSs stay at fixed positions year after year without regular dry docking for inspection and repair. Since they cannot move off station they must withstand whatever weather comes their way. Hence, depending on location, at times their mooring systems need to withstand high storm loadings. Typically, during design for harsh environments, mooring systems do not have much reserve capacity above what is required to withstand survival conditions. Therefore, deterioration of the lines over time can increase the likelihood of single or multiple line failures. Multiple line failure could conceivably result in a FPS breaking away from the moorings and freely drifting in the middle of an oil field as has been seen in the past – see Section 4. Failure of two adjacent mooring lines mooring lines at the same time due to wave shock loading has been seen and this could have serious implications if the risers are pressurised at the time.

This JIP is concerned with assessing how mooring systems have performed in the field to identify the level of degradation which has taken place. Hence, the JIP has looked at FPSOs, Semi-submersible production units and Spars through out the world. From the survey it has become apparent that certain, potentially significant, problems have occurred and thus the JIP wishes to publicise these so that they can be taken account of during inspection of existing units and during the design of future units.

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1.3 Indicative Mooring Statistics

At the beginning of the project it was hoped that it would be possible to gain data on the mooring performance on most of the FPS’s (turret and spread moored FPSOs, production semis and Spars) in the world. In practice the best data which has been obtained is for North Sea Units, partly due to local contacts and also the rigorous reporting regime in this area. In the absence of more comprehensive information, it thus seems prudent to consider official statistics for this region to be the best available indicator of the likelihood of mooring failure. Exactly how these statistics can be related to milder environments is difficult to quantify based on the presently available data set.

Table 1-1 summarises failure statistics for North Sea operations for different floating units covering the period 1980 to 2001. It is clear from these statistics that the probability of line failure per operating year is relatively high.

Type of Unit Number of Operating

Years per Failure

Drilling Semi-submersible 4.7

Production Semi-submersible 9.0

FPSO 8.8

Table 1-1 - North Sea Mooring Line Failure Data, 1980 to 2001 [Ref. 1]

Given the safety critical nature of mooring lines and the likelihood of failure one might imagine that they would be heavily instrumented with automatic alarms which would go off in case of line failure. The following indicative statistics, based on data from the majority of North Sea based FPSOs, give an indication that instrumentation is not as prevalent as might be expected for such a heavily regulated region:

50% of units cannot monitor line tensions in real time,

33% of units cannot measure offsets from the no-load equilibrium position,

78% of units do not have line failure alarms,

67% of units do not have mooring line spares available,

50% of units cannot adjust line lengths.

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1.4 The Cost of Mooring Line Failure

If a multiple mooring line failure should occur in storm conditions the potential cost and the implications for the whole FPS industry could be extremely high, depending on circumstances. Even a single mooring line failure would be costly as is illustrated in Table 1-2 for two different case studies, further details can be found in Section 5.4.

Description Approx. Cost of

Single Line Failure

50,000bpd N. Sea FPSO £2M

250,000bpd W. African FPSO £10.5M

Table 1-2 - Indicative Single Mooring Line Failure Costs

1.5 Key Findings from the Survey

During the course of the project a few common themes emerged which are outlined below:

Wear where the Lines Connect to the Surface Platform

Achieving material compatibility at the key turret interface is vital – see Section 0. Whether the trumpet pivot point should be in board or outboard of the chain stopper needs further consideration for new designs. In addition, whether rotation should be permitted in two planes, rather the one which is typically the case at present also requires addressing based on further in field experience. This may have particular implications for spread moored FPSOs. Access for inspection of these areas also needs to be improved and this should be specified in the mooring design criteria – see Section 20.

Wear/Corrosion Allowance for Long-Term Moored Units

On two North Sea FPSs chain wear and corrosion has been found to be significantly higher than what is specified by most mooring design codes. More in field inspection data is needed to find out if this is a general finding, which could have long-term implications for other FPSs in the North Sea and elsewhere.

Excursion Limiting Weighted Chain Designs

A number of excursion limiting weighted chain systems have experienced problems – see Section 10.3. Great care is needed in the design of such systems; particularly if they are due to operate in adverse environmental conditions. Parallel chains seem to have worked well, as opposed to clump weights (lump masses) or hung off chain tails. Clean catenaries, i.e. without buoys or clump weights seem to work best, although water depth, riser offset limits and environmental conditions may mean that this is not always possible.

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Local Design of Connectors

Connectors are vital components on any mooring system and they need to be very carefully designed if they are to prove reliable over a long field life. Certain mooring problems have been due to the local design of the connectors. Section 14.4 includes a summary of key items which should be considered during detailed connector design. There is an emerging need for the development of a fatigue resistant connector suitable for use with mooring chains during repair/overhaul operations.

Friction Induced Bending

Friction induced bending fatigue appears to be a significant issue which has been somewhat neglected and warrants further investigation. This was less of an issue for catenary systems in moderate water depths. Deep water taut moored units seem to be potentially particularly susceptible – see Section 15.2.

1.6 Key Areas to Check on a Mooring System

Based on the survey results,

Figure 1-1 illustrates the key areas which should be inspected on a mooring line. The FPS has been displaced by environmental forces, thus illustrating both windward and leeward mooring lines.

Figure 1-1 - Red Arrows Indicate Key Areas subject to Degradation on a Mooring System (leeward likely to have worst wear)

From a number of units it has become clear that the less loaded leeward lines can be subject to greater degradation than the windward lines. This seems to be due to greater relative rotation on leeward lines since the line is typically under lower tension.

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1.7 What are the Best Ways to Detect Line Failures?

It is vital to detect line failures promptly or else there is a danger of a unit entering a storm while still producing and thus being at an increased danger of loosing another mooring line.

Detecting a line failure in the mud is difficult since the catenary shape, depending on sea-bed conditions, may not change that much. Section 17 summarises the key detection techniques available at present. It is clear that in-field trials are required to identify what systems prove to be reliable over the long-term. Hence, this is an on going issue which requires monitoring, assessment and publicising of the key findings.

1.8 Inspection Technologies

Inspecting moorings lines in situ is desirable due to the danger of damage during line recovery to the surface and also during re-installation. There is also a significant cost involved in mobilising intervention vessels to recover lines to the surface and then re-install them.

In-water line inspection is difficult, particularly with respect to identifying possible cracks. Despite this it has become clear that many possible problems can be identified early on, using tweaks to existing technology. This has been successful as long as suitably experienced people are involved in planning the inspection process and examining the results.

Section 18 summarises the present available inspection technologies and includes a prioritised list of possible future improvements.

1.9 Key Conclusions and Recommendations

The survey of past and presently operating FPS units has shown that serious incidents have occurred in the past including loss of station. The survey has also shown that even for more up to date designs, deterioration of certain areas of the moorings system may be more rapid than expected. As well as the detail issues there is a more general issue that requires addressing, namely the manner in which mooring integrity is managed and audited on an on-going basis.

Since moorings are category 1 safety critical systems, if the deterioration is not detected early and monitored/rectified the consequences could be severe. Hence, it is vital that whoever offshore is responsible for the day to day operation and inspection of FPS moorings should have a strong marine background, such as a Deck Officer or Marine Engineer. Such personnel have a suitable mindset in that they really understand the importance of moorings and their likelihood to deteriorate significantly over time. It is important that these personnel should be provided with sufficient resources so that they can be pro-active with regard to inspection and any possible repairs which may be required.

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Semi-submersible units have accumulated hundreds of years of mooring experience for varied world wide locations. A key point to learn from such units is that chains, wire ropes, gypsy wheels, stoppers and connectors have finite lives and do wear out. Although drilling rigs deploy and recover lines fairly regularly, which can cause damage, the wear seen on production semis is still significant – see Section 7.1. However, most large scale FPS with 20+ year design lives seem to have been built on the expectation that the mooring lines will last for the life of the field and that safety will not be compromised towards the tail end of the field life, when production rates have dropped. If production rates have dropped there is less money available for mooring line repairs. Hence, assessments should be undertaken during the field life to assess whether line change outs may be required in the future and if so contingency money should be allowed for to cover this later expenditure.

In general, moorings should be thought of as relatively vulnerable primary structural members subject to constant dynamic motion. Expecting such systems to last for 20+ years without overhaul may prove to be optimistic. The commercial risks associated with a line failure during the field life justify the selection of top quality equipment from the outset. This equipment then needs to be regularly inspected and repaired as required to ensure that it is still fit for purpose.

Availability of mooring line spares including connectors is extremely variable. Given the several month lead-time associated with procuring new components, it is recommended that each operator should identify short term remedial measures to repair a line if it fails. This would involve identifying commonly available components which can be obtained at short notice from marine equipment rental companies. Outline procedures including the type of intervention vessel required should also be developed.

Mooring systems are not as simple as they first appear and they need careful management through out their design lives. Thus a life cycle approach to mooring design and operation is recommended. In this way designers can feedback their inspection requirements to Operators and then learn from whatever is found during inspection. Manufacturers should also be included in this feedback loop, since they may be best placed to implement improvements to their products. Hence over time mooring design and manufacturing should improve. At present designers and manufacturers are not always involved with the in field behaviour mooring systems. Therefore, they may not be aware of operational or inspection type issues. In general there seems to be a need for periodic Mooring Audits to re-assess original design parameters and review inspection records to assess whether the system is still fit for purpose.

It is clear from this state of the art review that to continue to improve mooring integrity a number of topics still require further investigation. A bullet point list is included in Section 21.3.

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2 INTRODUCTION AND SCOPE

2.1 The Need for a JIP

The number of Floating Production Systems (FPSs) operating in the world increased substantially during the 1990’s and there is now an ever-increasing body of FPS operational experience. In 2001 Noble Denton was commissioned by the UK Offshore Operators’ Association (UKOOA) to review available operational data from the British sector. The key results to emerge from this study were as follows:

There has been one FPSO line failure for every 5.4 operating years (this figure has been updated during this study);

Several cases occurred in which there was systematic damage to more than one line;

Particular problems have been experienced at connectors and interfaces;

In no cases was the damage recognised immediately;

Long-term failure rates remain uncertain.

The study concluded that the potential for multiple line failure is greater than is commonly perceived, and this should be a major cause for concern. The main reasons for this situation are:

Available inspection and maintenance provisions can allow long periods in which single or multiple defects can remain undetected;

Most UK sector FPSOs can not detect if they have ‘lost’ a mooring line;

The risk of mooring line failure is often underestimated and the majority of operators do not carry spares or have systems in place for dealing with a line failure;

Design codes and standards give little guidance on terminations, connections, fair leads and stoppers which is where the majority of failures has been seen;

Similarly there is limited guidance on inspection, repair and maintenance.

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2.2 Scope Development

The JIP scope was developed to extend the previous UKOOA study to include international experience, and reassess the conclusions of the UK sector study in more global terms. In addition, a follow up has been carried on the recommendations of the UKOOA study to investigate the levels of exposure to duty holders, and developing measures to reduce the associated risks.

Specifically the work has covered the following:

Disseminate data gathered from international experience,

Develop guidance for designing mooring connectors and interface elements,

Provide guidance on mooring line inspection,

Summarise the pros and cons of line failure detection methods,

Take a look to future deepwater and taut leg applications

Investigate and report illustrative case studies

The JIP scope has been adjusted during the project to take into account results found to date and also the difficulties experienced in obtaining international data.

2.3 JIP Objectives

The basic objectives of the JIP are to:

Improve safety

Help to safeguard reputation of FPSO/FPS industry

Feedback operational and inspection to mooring designers

Publicise the importance and potential vulnerability of mooring systems

This report is intended to be read and understood by non mooring specialists such as FPS Operational staff. In this way the people who live and work on FPSs will be better able to become involved in the vital task of looking after their own mooring systems.

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2.4 Project Organization

The project organisation is illustrated in Figure 2-1.

Figure 2-1 - JIP Organisation

The scope of work was broken down into Cost, Time, and Resource Modules [CTRs], which were organized as follows:

Figure 2-2 - CTR Breakdown

Martin Brown Project Manager

Consultants: I.D. Williams, R Stonor, R Nataraja, D. Orr, R.V. Ahilan

ND Group Resources & Subcontractors

STEERING COMMITTEE

Nigel Robinson NDE Project Director

DESIGN AND CONSTRUCTION ISSUES

CTR 2 : Transportation, Handling & Installation Challenges

CTR 3 : Design of Connectors & Interfaces

DESIGN AND CONSTRUCTION ISSUES

CTR 2 : Transportation, Handling & Installation Challenges

CTR 3 : Design of Connectors & Interfaces

INTERNATIONAL SURVEY OF

MOORING PROBLEMS

CTR 1 : Survey of International FPSO/ FPS ExpCTR 4 : Consequences of Line Failure

INTERNATIONAL SURVEY OF

MOORING PROBLEMS

CTR 1 : Survey of International FPSO/ FPS ExperienceCTR 4 : Consequences of Line Failure

INTEGRITY MANAGEMENT

CTR 5 : Status Monitoring and Failure Detection

CTR 6 : Inspection, Repair & Maintenance, inc InWater Survey

CTR 7 : Sparing Options

DISSEMINATION

OF RESULTS

(CTR 10)

Lessons Learned

Detailed Report

Integrity Check List

DISSEMINATION

OF RESULTS

(CTR 10)

Lessons Learned Bulletins/Steering Committee briefings

OTC paper

Detailed Report

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2.5 Project Participants/Sponsors

The following list details the organisations which have sponsored the JIP plus the personnel nominated to the Steering Committee. It is worth noting that the Steering Committee meetings provided an excellent mechanism to obtain and distribute data. Thanks are given to all members of the committee and the Chairman for their participation.

1. ABS, Rod Yam and Ernesto Valenzuela

2. Ansell Jones

3. Balmoral Group, Doug Marr

4. Bluewater, Simon Stauttener

5. BP, Richard Snell, Peter Gorf and Steve Barron

6. Bureau Veritas, Frank Legerstee and Michel François

7. Chevron Texaco, Matthew Brierley, Paul Devlin, and Jim Hughes (corresponding member)

8. ENI (Agip), Les Harley and Bill Nicol

9. Hamanaka Chains, Yoshiyuki Kawabe

10. HSE, Martin Muncer and Max English

11. IMS/Craig Group, Alan Duncan and Mark Prentice

12. Lloyds Register, Douglas Kemp, Richard Bamford and Alwyn McLeary

13. MARIN, Henk van den Boom and Johan Wichers

14. Maersk Marine Contractors, Graham Kennedy and Vere MacKenzie

15. National Oilwell/Hydralift-BLM, Philippe Gadreau

16. Norsk Hydro, Tom Marthinsen

17. Offspring International, Nigel Grainger and Russell Glen

18. Petro Canada, Sherry Power and Scott O’Brien

19. SBM, Philippe Jean (Chairman)

20. Statoil, Kjell Larsen

21. Vicinay Cadenas, Dave Nicol and Eduardo Lopez

22. Welaptega Marine, Tony Hall

Many people from various organisations helped out through out the JIP by providing information. It is impossible to list them all, but their combined support has been crucial in enabling a comprehensive picture to be pulled together. Particular thanks are, however, given to Amerada Hess/Wood Group and Mr Ian Williams for making highly relevant data readily available to the JIP. Thanks also to Diane for all her assistance with the layout and editing of this document.

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2.6 Steering Committee Meetings

The Steering Committee met four times during the course of the JIP in Monaco, Aberdeen, Paris and Houston, all being well attended. The meetings in Monaco and Paris were part of the FPSO Forum/JIP Week. The Aberdeen meeting was a standalone meeting.

The final meeting in Houston was at the end of the 2005 Offshore Technology Conference (OTC).

Figure 2-3 – Participants at the Steering Committee meeting in Paris

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3 MOORINGS OVERVIEW

3.1 Mooring Basics

3.1.1 Restoring Forces

To appreciate how to preserve the integrity of a mooring system it is helpful to have a basic understanding of the different types of mooring systems and how they work. This subject is covered in this chapter, which also includes a simple introduction to how such systems can be analysed.

The primary purpose of a mooring system is to maintain a floating structure on station within a specified tolerance, typically based on an offset limit determined from the configuration of the risers. The mooring system provides a restoring force that acts against the environmental forces which want to push the unit off station. In the following diagrams the main components of mooring system restoring force are explained.

The connection between the mooring system and the body of the vessel is where the restoring force of the mooring system acts, see Figure 3-1. At this connection point there are two force components present; horizontal and vertical. The horizontal component of the mooring line’s tension acts as a restoring force. The vertical component acts as a vertical weight on the vessel. In deep water the vertical force can be quite considerable. For some designs of FPS, with limited payload capacity, the vertical mooring force can have significant design implications.

Figure 3-1 – Typical Turret Moored FPSO

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It is informative to understand the significance of the mooring line angle as it departs the point of connection to the vessel. A low angle to the vertical will generate a low restoring force, with significant vertical load on the vessel. If the angle here is large, then the restoring force will be increased while the vertical load on the vessel will be reduced. This relationship can be seen in Figure 3-2. The vessel needs to be able to support the applied vertical loading.

Figure 3-2 – Shallow and Steep Mooring Line Angle Illustration

The relationship outlined in Figure 3-2 is adequate for considering a 2 dimensional scenario. The mooring of a vessel, however, is a 3 dimensional problem and to this end it is necessary to consider the angle of the mooring line in the plane of the sea-surface. With reference to Figure 3-3 it can be seen that the tensions in a mooring line are split into two components; the restoring force that opposes the environmental loading, and the lateral force, which may balanced by another mooring line.

Figure 3-3 – Line Heading Illustration

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3.1.2 Environmental Loading

When there is no external loading on the system the vessel will not move from its static equilibrium position. When environmental loading does occur an imbalance in the system will occur. To restore equilibrium the mooring system restoring force must become equal to that of the environmental load. This is achieved through the vessel offsetting from its original position. As this occurs the ‘windward’ lines will pick up tension and the ‘leeward’ lines will shed tension. This is shown in Figure 3-4.

Figure 3-4 – Definition of Windward and Leeward Lines + Environmental Offset

The vessel will offset until the ‘windward’ lines have generated a restoring force that balances the environmental loading. This means that the distance between the anchor and fairlead will increase, and thus the tension at the fairlead will also increase. This is shown in Figure 3-5.

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The relationship between environmental load and vessel offset is often represented in a ‘Load – Excursion’ curve, as shown in Figure 3-6. This figure illustrates the load excursion characteristics of a 1,200m long, 76mm nominal diameter chain in 100m water depth with a working or pretension tension of 100te. The plot emphasizes the need to model the axial elasticity, even for chains, in order to get realistic results. Axial elasticity depends on geometry and material. Since there are new materials and geometries available in the market, it is important that designers should confirm with manufacturers that the values they are using agree with full scale testing values.

Figure 3-5 – Offset Position and Tension Effect

Figure 3-6 – Illustration of Load Excursion Curve [Ref. 2]

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3.1.3 Mooring Configuration

The most common mooring configurations are Spread Moored and Single Point Mooring systems, which are taken to include turret systems. The key attributes of each are discussed in this section.

Spread Mooring

This conventional mooring approach is widely adopted for semi-submersible drilling/flotel/production units. For floating production applications, spread moorings are used primarily with semi-submersibles and non-weathervaning FPSOs (i.e. no turret) – see Figure 3-7. Since the wave loading on a semi-submersible is relatively insensitive to direction, a spread mooring system can be designed to hold a semi on location regardless of the direction of the environment, although there is probably an optimum heading. However, a spread system can also be applied to ship-shaped vessels, which are more sensitive to environmental directions, as long as the environmental conditions are relatively benign and the weather direction is fairly uniform without strong cross currents. In a location such as the North Sea, the forces which can be generated on the beam of a spread moored FPSO, plus the motions in such conditions, effectively prohibit such a mooring arrangement.

The mooring lines can be chain, wire rope, fibre rope or a combination of the three. Either conventional drag anchors or anchor piles can be used to terminate the mooring lines.

Figure 3-7 - Typical Spread Moored Unit, Girassol FPSO offshore West Africa (courtesy of Stolt Offshore)

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Spread moorings are typically cheaper than turret moorings since they are mechanically far less complicated. However, they are limited to where they can be used and they can make offloading operations by a shuttle tanker somewhat more involved.

Single Point Moorings (SPMs)

Single point moorings (SPMs), such as internal or external turrets, are used primarily for ship shaped units – see Figure 3-1. They allow the vessel to weathervane, which is necessary to minimise environmental loads on the vessel by heading into the prevailing weather. There is a wide variety in the design of SPMs, but they all perform essentially the same function.

3.1.4 Catenary and Taut Leg Moorings

Two main types of mooring system can be used for either the Spread or Single Point system; Taut-Leg and Catenary. Both methods allow the system to withstand the applied forces, but through different mechanisms.

A ‘catenary’ system generates restoring force through the lifting and lowering of the line onto the seabed, plus a limited amount of line stretch. This is shown in Figure 3-8 with a typical arrangement shown in Figure 3-9.

A ‘taut-leg’ system makes use of the material properties of the mooring line, namely its elasticity, as shown in Figure 3-10. A typical taut-leg arrangement is shown in Figure 3-11. Taut-leg moorings are relatively new and are typically used in deep water to limit FPS offsets.

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Figure 3-8 – Illustration of Catenary System

Figure 3-9 - Typical Spread Moored Catenary System (Courtesy of Vryhof)

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Figure 3-10 – Illustration of Taut-Leg system

Figure 3-11 - Typical Spread Moored Taut-Leg System (Vryhof)

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3.1.5 Vessel Dynamics

Waves will cause a vessel to move in all six degrees of freedom; surge, sway, heave, roll, pitch and yaw. These degrees of freedom are illustrated in Figure 3-6.

The motion of the vessel to individual waves is called its wave frequency or first-order response. As a mooring line moves through the water it will be subject to dynamic line drag and inertia loading and sometimes a whipping effect. It is possible to take this into account by undertaking a dynamic mooring analysis, but this does increase computing time significantly.

Figure 3-12 – Illustration of Surge, Sway, Heave, Roll, Pitch and Yaw

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The compliance of a mooring system is such that conventionally the presence of the mooring system is not considered to affect the wave frequency response. The overall mooring system stiffness and associated natural frequency will influence its second order or low frequency slow drift response.

In deep water for certain floating objects, such as deep draft Spars, the wave frequency motion is attenuated to a certain extent by the mooring system due to the higher system stiffness. Hence, a coupled analysis is sometime undertaken. The general conclusion from this type of analysis appears to be that the mooring quasi-static tension has an impact on a floater's wave frequency response, which in turn will affect the mooring dynamic tension. On the other hand, the effect of dynamic tension is less important to a floater's wave frequency response. For deep water the effect of risers on the vessel response becomes increasingly important and this should be taken into account.

The coupled wave frequency motion of a floater can be calculated in the time domain using the wave force, wave frequency added mass and damping, and mooring force at each time step. Usually a convolution method needs to be adopted in the radiation force calculation. Although the coupled wave frequency motion calculation in the time domain is slower than the Response Amplitude Operator (RAO) based wave frequency motion calculation, it is still acceptable. Typically a 3 hour simulation will take a few minutes. However if there is very high mooring stiffness or if a mooring dynamic analysis is performed, then the computing time will be high.

3.1.6 Mooring Design

The tensions experienced by a mooring system at any time are driven by the following:

Static component from Wind, Mean Wave Drift and Current,

Wave frequency component, caused by 1st order wave frequency motions and drag/inertia effects on the line,

Low frequency component, due to 2nd order low frequency waves and wind dynamics.

The essence of mooring design is to optimise the behaviour of the mooring system such that the excursions of the surface vessel do not exceed the allowable flexible riser offsets, while at the same time ensuring that the line tensions are within their allowable values. Thus the mooring system load offset curve should not be too hard or too soft – see Figure 3-13. Hence, considerable iteration work may be required to optimise a system for a particular location.

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It is worth noting that spring buoys (mid water buoys) and clump weights can also be used to obtain an optimised mooring system stiffness by extending the resistive forces over greater distances, hence allowing clearance over subsea features. However, their use should be treated with caution, particularly in areas subject to harsh environmental conditions, where they have been known to come adrift – see Section 9.3. Buoys and clump weights are also likely to introduce bending effects which may have an undesirable impact on the fatigue life – see Section 15.

Figure 3-13 – Example of Optimising the Stiffness of the Load offset Curve

3.1.7 Mooring Analysis Calibration with Full Scale Behaviour

The determination of maximum tensions for a multiple line system requires application of specialist computer programmes, which in many cases have been under continuous development for a number of years. Despite this, there are still uncertainties in estimating mooring loads using analysis software and model tests. Hence, it would be desirable to compare the behaviour of a full scale FPS in known weather conditions versus predictions. Surprisingly little work has been done on this topic, although this is partly due to the difficulties associated with obtaining reliable weather and instrumentation readings.

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3.1.8 Active Winching and Thruster Assistance

Since there are now hundreds of years of accumulated mooring experience from semi-submersible rigs, it is informative to understand the basis of their mooring operations. This is reviewed in this section, which considers active winching and thruster assistance.

Active Winching

Active winching can be undertaken on semi-submersible production, drilling and accommodation units. There are two basic options, namely:

1. Leeward line slackening,

2. All round length adjustment, including windward lines, so that the tensions are as well balanced as possible at the limit of vessel surge.

If the leeward lines are slackened down too much this can result in greater yawing/surging and reduced direction control which can lead to higher line tensions. In other words, if there is too much slack in the system, there is an increased danger of high line snatch loadings.

Windward line tension optimisation can also be problematic. To quote from Robert Inglis’s informative 1992 paper [Ref. 3]:

“in practise rig operators are reluctant to adjust windward line tensions in severe weather conditions and usually restrict adjustments, if any, to slackening leeward lines. This is partly to do with limitations in winch stall capacity and the risk of a winch or brake failure, but most importantly the majority of rigs are not provided with suitable tension monitoring devices and computerised winch control systems which would make extensive line tension optimisation a realistic possibility. The general situation is that analysts frequently utilise line optimisation to reduce tensions to meet acceptance criteria but these line tension optimisation procedures are almost never implemented in practice on a rig.”

Based on this type of feedback the latest mooring design codes (e.g. ISO [Ref. 4] + OS E301 [Ref. 5]) do not permit either windward or leeward active wincing to minimise mooring line tensions apart from going from one operational state to another.

Thruster Assistance

A number of semi-submersibles and a relatively small number of FPSOs are equipped with thruster assistance. The thruster assistance can be categorised as either Thruster Assistance (TA) or Automatic Thruster Assistance (ATA). TA is based on manual joystick thruster control. ATA makes use of automatic remote control algorithm system to control the behaviour of the thrusters.

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It has been found that operation of the thrusters can be very effective in reducing peak line tensions; even though the thrust delivered can be modest. Typically in a mooring analysis the thrusters are considered to reduce the mean load applied to the mooring system. However, thrusters also seem to damp down the magnitude of the slow drift second order offsets. They can also be helpful with respect to heading control. This can be particularly useful on a production vessel, if a small change in heading can result in reduced vessel motions, thus improving the efficiency of the oil/water separation process.

In practical terms, when operating in manual thruster mode, high line snatch loads can be avoided by applying thrust as the wave train approaches. This will tend to push the vessel in the direction of the advancing sea. As the wave passes it is necessary to ease down on the thrust to avoid over slackening the windward lines. If these become too slack there is an increased danger of snatch loading when the next wave train passes through.

3.1.9 Metocean Parameters and their Impact on Mooring Integrity

For relatively benign environments, such as off West Africa, there is a much smaller difference between operational and survival sea states compared to say the North Sea. This means that if the metocean parameters, or the response of the vessel due to these parameters, is underestimated, there is significantly less of an in built safety margin compared to harsher climates, particularly with regard to fatigue.

The degree of spreading of the waves (see Figure 3-14 and Figure 3-15) can also affect mooring analysis results. The geographic area and fetch distance will influence the type of waves likely to be encountered in practice. Conventionally, short crested seas are considered to result in reduced wave frequency response and hence reduced mooring line tensions - see section 3.3.2 of [Ref. 6]. However, recent model test results at DHI in Denmark has shown that for certain vessel sizes the mooring loads in short crested waves can be higher than in long crested waves [Ref. 7]. Thus the key point is to ensure that the response of the system is thoroughly evaluated for the worst expected conditions (ie short or long-crested) both from a fatigue and a strength point of view.

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Figure 3-14 - Illustration of Long Crested (Unidirectional) Seas

Figure 3-15 - Illustration of Short Crested (Confused) Seas

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3.1.10 Rogue/Steep Breaking Waves and Shock Loading

Mariners have used phrases such as “Freak Waves, Rogue Waves, Walls of Water or even Holes in the Sea”, to describe some of the conditions they have experienced at sea. Trading vessels are typically weather routed to avoid the worst of predicted weather conditions. However, permanently moored FPSs have to ride out whatever weather is thrown at them.

From a statistical sense the longer a FPS is on station the more likely it is to experience 100 year + conditions. If an elderly FPS with a mooring system which has seen wear, corrosion and has accumulated some hair line cracks is subject to such conditions, the likelihood of single or even multiple line failure is increased.

Very occasionally an unusually steep wave slam load could occur at the same time that a floating structure is around its maximum slow drift offset. The resulting shock or spike load on the mooring might be quite considerable. How much this shock loading is transferred to the mooring lines will depend to a significant extent on the degree of structural damping in the hull structure, the vessel inertia, how long the load acts and where the moorings are relative to where the wave impacts. For a semi, where you might get wave slam/slap right into one of the corners (see Figure 3-16), the amount of structural damping might well be less than compared say to a FPSO with an internal turret (see Figure 3-19). Hence the loading could be higher.

Figure 3-16 - Example of a Wave Breaking on a Column of a Semi-Submersible

In deep water steep elevated wave fronts with breaking or near breaking crests can occur – see Figure 3-17. In addition, a "Three Sisters" wave group can occur in which the second wave is generally the highest and is often preceded by a long trough. Hence, a moored object may ride the first wave, but then plunge submerged into the base of the second steep fronted wave that then inflicts the greatest shock loading.

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Figure 3-17 - Illustration of Deepwater Breaking Wave Types (Plunging Break on the Left and Spilling Breaking on the Right)

In November 1998 the Schiehallion FPSO was struck by a wave which was felt throughout the vessel. The wave caused tears in the forward shell plating of the forecastle superstructure, buckling of supporting stiffeners and permanent deformation of the forecastle ‘tween deck – see Figure 3-18. Production was shut down and non essential personnel were evacuated to a nearby drilling rig. In this instance no damage was reported to the mooring system, but it illustrates the danger presented by infrequent steep breaking waves.

Figure 3-18 - Illustration of the Damage Caused to Schiehallion’s Bow by an Unusually Steep Wave (courtesy of BP)

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Present day standard mooring analysis tools do not evaluate this potential shock load effect on the mooring systems. Hence it is difficult to quantify. But there is a possibility, based on the wave description, that it could have been a factor which led to the virtually instantaneous multiple line failures experienced by “Petrograd 1” in the early 1990s (see Section 4.3). This might also be a factor in the relatively frequent mooring line failures experienced by semi-subs. It is recommend that this topic should be investigated further and that appropriate cross checks should be made with the real life recorded response of FPSs in severe/steep sea weather conditions. However, it also should be noted that such weather conditions do not occur very often.

Figure 3-19 - Model Illustration of the Effect of a Breaking Wave on a FPSO (Courtesy of APL website)

The right hand side photograph of Figure 3-19 is perhaps an example of the type of wave conditions which could impart a shock loading to the moorings, depending on the FPSO offset at the time. If a mooring line had already broken and its failure had not been detected (due to a lack of failure of instrumentation) the chance of additional line failures would be high in these conditions.

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3.2 Mooring Line Constituents

3.2.1 Introduction

Various different materials can be used to assemble a mooring line. This section provides a brief description of the main components that typically constitute a mooring line. The pros and cons of the various types of line components are explained. This helps to aid understanding when considering how actual systems have performed in situ. Connectors and terminations are considered separately in Section 14.

3.2.2 History of Studded and Studless Chain

Early mooring lines tended to make use of simple links without studs. Development of this design led to usage of studded links, see for example Figure 3-20. Ease of handling and avoidance of kinking were the primary reasons for the introduction of studs. The resulting link geometry (see Figure 3-21) took advantage of the ability of the stud to resist some of the bending loads in the links. The studded link standard geometry of length of 6 x Bar Diameter (D) and breadth of 3.6 x D was approved by the British Admiralty in the 1860s.

Historically anchor chain used on ships was, in general, only required to meet intermittent short term loading and therefore, even over a long ship service life, fatigue was unlikely to be a problem.

Figure 3-20 - Isambard Kingdom Brunel in front of Studded Chain for the “Great Eastern” steam ship, circa 1858

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Studless Link Studded Link

Figure 3-21 – Comparison of the Geometry of Modern Studded and Studless Chain

[Note: DNV Cert Note 2.6, states 3.3D to 3.4D for the of studless link width]

Fairly recent long-term applications of chains in the moorings of floating production systems have brought about the development of studless chain. The studless chain link has been redesigned with a smaller breadth to reduce the bending loads. These designs are increasingly used for long-term moorings because loose and missing stud problems are eliminated. Unfortunately, however, the fatigue life of studless chain has been shown to be half that of comparable studded chain, based on the results of fatigue testing [Ref. 8]. In other words the fatigue endurance of studded chains is twice that of studless if the studs remain tight. Of the 70 fatigue failures reported in the Houston JIP, 52% occurred at an inner Half-Crown position, 34% at an inner Crown position and 14% at a mid leg position. The Crown refers the area of maximum bend and Half-Crown essentially refers to the area of the link where bending commences.

The studless link standard geometry of length of 6 x D and breadth of 3.35 x D came to the market after 1989 as consequence of collaboration between DNV and Vicinay for the Veslefrikk B project. For this chain the first tentative specification went out in 1995 with the DNV’s Certification Note 2.6. More recent developments include customised chain geometries also known as Variable Geometry and Weight (VGW) as discussed in OTC paper 8148, 1996 [Ref. 9]. VGW provides flexibility to modify link geometry and weight to suit a particular application – see for example Section 18.8.2.

Table 3-2 and Table 3-3 summarise the relative merits of studless and studded chain in terms of design, manufacturing, inspection and maintenance.

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RequirementRecommended

Chain Reason

Lower static or dead weight in the catenary Studless Lower weight per metre

Access for shackle and accessory connection

Studless More interior link space

Versatility, similar to end links Studless Completely open links

Greater safety factor with same weight per metre in the catenary (strength to weight ratio)

Studless Larger possible diameter with less weight per metre

Greater stiffness in the mooring line Studlink Higher elasticity modulus

Higher Break Load Both Same break load, but different proof loads

Transition through windlasses and fairleads

Both But studless more likely to knot or twist

Long fatigue life Open to discussion See previous page

Table 3-1 – Summary of Chain Design Parameters (modified from Vicinay ChainCatalogue)

RequirementRecommended

Chain Reason

Better inspection of weld and crown area Studless Greater access due to lack of stud

Elimination of stud locating problems Studless Lack of stud

Oversizing of the link in the weld zone Studless Elimination of the flattening and material expansion in the weld zone

No links with stud looseness Studless Lack of stud

Table 3-2 – Comparison of Manufacturing Parameters

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RequirementRecommended

Chain Reason

Eliminate premature fatigue due to loose studs

Studless No stud, therefore no notch effect

Reduce inspection/repair costs Studless Easier access + no loose studs to repair

Eliminate galvanic reaction between the stud and the link

Studless No stud, therefore no possibility of reaction

Increase reliability of the chain over time To be determined Although there are no loose studs issues with studless, the fatigue performance of studless is less good than that of studded

Handling and connectability with D shackles and hooks

Studless Better access for the through pin. Minimal requirements and restrictions

Early indication of system degradation Studlink Condition of studs likely to be representative of system as a whole

Handling and Manoeuvrability with respect to bending shoes and chain stoppers

Both Certain restrictions, in general studless chain is more likely to knot than studded

Table 3-3 – Chain Geometry Implications for Inspection and Maintenance

3.2.3 Effect of Loose Studs

Offshore oil industry experience with studded chains has shown that during use, the studs start to get loose and the seat of the studs is often the initiation point for fatigue cracking [Ref. 2 and Ref. 11].

The BOMEL JIP [Ref. 10, p.54] showed that the Stress Concentration Factor (SCF) in a studless link (a link in which the stud has been removed as opposed to a link designed to be studless which has a different geometry) is much higher than in a studded link, i.e. 5.3 compared to 3.8. It follows therefore that a link with a loose stud is likely to have a much shorter fatigue life than one where the stud is properly fitted.

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Sandberg’s report [Ref. 12] discusses the effect of loose studs and reports the following: (Page 11) “This ovalization occurred at the point where the edge of the footprint forms a notch effect, which in some instances appeared quite severe. It was at this point that the fatigue cracks were initiated and then propagated through the side of the link. However, on page 16 Sandberg advised that “Not all loose studs had developed cracks even where the end of stud play was up to 4.0mm indicating that many factors play a part in the initiation and propagation of these cracks including the ultimate tensile stress (UTS) of the studs. The mechanical properties for the stud are important, particularly with regard to yield strength, for the setting of the chain under the proof load. If the properties are not correctly balanced then fixing of the stud may be significantly impaired which can affect the future serviceability of the chain”.

Figure 3-22 shows a SPATE contour map which gives a crude indication of how a loose stud can affect the stress distribution in a studded link where the stud has become loose. The basic theory behind SPATE (Stress Pattern Analysis by Thermal Emission) is the detection of minute changes in surface temperature due to the pseudo adiabatic response of a material under stress. Through an infrared detector, scanning the surface of a given material, relative changes in temperature are fed to a computer system for correlation and finally presented as a pictorial colour image of the stress pattern over the scanned area. These pictures can be interrogated further to obtain stress values at any given point. As the stresses in the three principal planes contribute to the overall temperature change, stress values obtained are a summation of the principal stresses generated by the dynamic loading in each plane.

Figure 3-22 - “SPATE” Contour Map of a 76mm Loose Stud Chain Link [Ref. 8]

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Asymmetric Studs

Asymmetric studs were developed to reduce the amount of loose studs experienced in the field. The Asymmetric stud is designed in such a way that gives equal foot prints on either side of the link – see Figure 3-23. In studlink chain, the ‘asymmetric’ stud design is claimed to provide ‘more equal stud indentation and contributes to a more symmetric stress distribution in the link’.

Figure 3-23 - Example of the Arrangement of an Asymmetric Stud

During manufacturing of the formed link, the flash butt weld (FBW) side of the link is still very hot by the time the process brings the link to the stud press. Hence there is a very hot side and the other side of the link, the parent material, which has already started to cool, is therefore at a lower temperature. With a normal stud the cold stud, when pressed into the link will, on the hot side, sink deeper into the FBW and to a much lesser extent on the parent material side. Thus, if you inspect stud link chain with a stud missing you can quite often see there is almost no foot print on the parent material side.

The asymmetric stud provides equal foot prints on both sides. The asymmetric stud is then pressed to allow it to expand thus locking the stud in place. The actual configuration of the stud faces are different compared to the standard studs, because the edges of the asymmetric stud are more rounded to reduce the chance of notches or crack initiation under the studs, the studs are also flatter on one side so the stud cannot sink into the hot FBW and more rounded on the other side to fit the form of the link on the parent material side. In addition, when the studs are expanded it puts a spring effect into the link thus assisting to keep the studs in place.

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3.2.4 Chain Grade and Ultimate Tensile Stress

There are a variety of chain grades available, each of which are distinguished by the differing yield strengths of the steel that are used in their manufacture. The Grade 1 chain (designated Q1, U1 or K1 depending on whether Continental, UK or Norwegian specification) was developed using mild steel. This grade of chain is not now used in offshore mooring systems. The most important chain grades for the offshore industry are as follows:

Oil Rig Quality (ORQ), dating from the beginning of the 1970s with 641MPa issued by API

R3, dating from the mid 1980s with 690 MPa to meet ORQ + 10%

R3S, with 770 MPa to meet ORQ + 20%

R4, with 860 MPa

R4S with 950 MPa or R4 + 10%

R5 with more than 1,000 MPa

R is the standard International Association of Classification Society (IACS) terminology for offshore mooring chains. Interestingly, none of the Certification Notes for any of the Certifying Authorities actually lay down detailed minimum alloy content for specific grades.

It is important not to confuse standard Ship or Marine Grade chain with offshore R grade chain. In other words Grade 3 is different from R3. Table 3-4 below summarises the characteristics of Marine Grade chain:

Description Ultimate Tensile

Strength (MPa or

N/mm2)

Marine Grade U1

Wrought iron or mild steel 310

Marine Grade U2

Special Quality Steel 490

Marine Grade U3

Extra Special Quality Steel 690

Table 3-4 - Summary of Ship or Marine Grade Chains [Ref. 13]

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3.2.5 Chain Grade and Hardness

Surface hardness values based on, for example, Brinell or Vickers Hardness Testing are not normally reported for different chain grades, although API 2F [Ref. 65] (section 5.5) and DNV Certification Note 2.6 [Ref. 18] (section 6.6.4) mention that such values should be obtained during manufacture.

In Table 3-5 Vicinay has reported surface hardness values for various grades of chain. It should be noted that the tests were undertaken on non polished services and thus the values should be considered to be indicative only.

Chain Grade Surface Hardness (Brinnell (HB)

Grade 3 220 – 250

R3 235 -260

R3S 250 – 275

R4 275 – 305

R5 305 - 325

Table 3-5 – Example of Indicative Surface Hardness Values for Various Chain Grades (courtesy of Vicinay)

The applied tension in a link and hence the resulting stresses could conceivably result in a change in surface hardness. Vicinay has investigated this point and concluded that “the increase in superficial hardness of chains, due to tension, is insignificant.”

One oil company chain specification states that the maximum hardness should not exceed 350 HV10 (HV = Vickers hardness, similar to Brinnell in this range of numbers) mainly due to a sensitivity to hydrogen induced crack growth. In general the higher the hardness the more the sensitivity increases, but this depends on steel composition. It is the minimum yield stress that determines the minimum hardness.

3.2.6 Charpy Impact and CTOD Tests

Charpy Impact test energy measurements are available for different chain grades. A Charpy Impact test will give an idea of the ductility of the material and its susceptibility to brittle fracture depending on the temperature. Therefore a Charpy test does not give a full picture of surface hardness. Charpy is concerned with mechanical fracture of the material. For the same steel the mechanical of fracture is more related to structural metallurgical.

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During chain manufacture Crack Tip Opening Displacement (CTOD) values should be evaluated both for the main body of the link and for the weld. For example Table 10-5 of DNV Certification Note 2.6 [Ref. 18] provides critical defect sizes which the metal should achieve. CTOD gives a better indication of Fracture Toughness, compared to

Charpy-V impact test which only gives an indication of the toughness of a metal.

It is worth noting that the temperature of the test is important because almost all steels have a zone of high stable values over a "plateau" region. But suddently, within very few divisions of temperature variation, they fall to a zone of lower values.

3.2.7 Manufacturing Tolerances and Implications for Wear

Figure 3-24 and Figure 3-25 show typical chain manufacturing tolerances. The implications of these types of tolerances are discussed in more detail in Section 18.6.

Figure 3-24 – Indication of the Manufacturing Tolerances of Studless Links (courtesy of Vicinay)

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Figure 3-25 – Studlink Manufacturing Tolerances (courtesy of Vicinay)

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3.2.8 Wire Rope

Figure 3-26 shows the normal wire rope construction types used for offshore mooring lines. Six strand independent wire rope core (IWRC) is typically used for mobile drilling units due to its lateral flexibility and relative cheapness. Spiral strand wire is generally torque balanced, the implications of which are discussed in more detail in Section 6.2.2. Sheathing has been introduced to protect the wire from corrosion. It will, however, be interesting to see if, over time, the sea water ingress causes corrosion underneath the sheathing. At present there are no real techniques available to monitor such corrosion, see also Section 18.8.

Figure 3-26 - Illustration of the Make Up of Different Wire Rope Types (courtesy of Bridon)

The yield strengths of steel used in the construction of wire mooring ropes vary but are very high, for example see Table 3-6.

Construction Ultimate Tensile Stress (N/mm2)

Six strand (IWRC) 1860

Spiral strand 1570

Table 3-6 – Illustration of Indicative Wire Rope Material Properties [Ref. 2]

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The two main wire rope types utilised have differing properties. The pros and cons of the two rope constructions are summarised in Tables 3-6 and Table 3-8:

Spiral Strand – Advantages Six Strand - Advantages

Higher Strength to Weight Ratio Higher Elasticity

Higher Strength to Diameter Ratio Greater Flexibility

Torsionally Balanced Lower Axial Stiffness

Higher Resistance to Corrosion

Higher Fatigue Resistance

Table 3-7 - Comparison of the Advantages of Spiral and Six Strand Wire (courtesy of Bridon)

Spiral Strand – Cons Six Strand – Cons

Easy to kink during installation – see Figure 6-7

Introduces torque into a mooring line

More expensive than six strand Typical design life of 5 to 8 years

Table 3-8 - Comparison of the Cons of Spiral and Six Strand Rope

Mooring wire is zinc galvanised to provide defence against corrosion; the major factor along with fatigue determining mooring line service life. Heavier zinc coatings are used on the larger wires of the spiral strand product enhancing corrosion protection properties. The larger outer wires of the six strand product may also use heavier zinc coatings to increase the attainable design life. An anti-corrosion blocking compound may be applied during manufacture to add a further corrosion prevention measure. Typical service life expectancy is shown in Table 3-9.

Design Life Recommended Product Type

up to 6 years Six Strand

up to 8 years Six Strand c/w zinc anodes

up to 10 years Six Strand c/w 'A' galvanised outer wires & zinc anodes

10 years plus Spiral Strand

15 years plus Spiral Strand c/w Galfan® coated outer wire

Table 3-9 - Wire Rope Recommendations for Varying Field Lives (courtesy of Bridon)

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Wire rope suppliers can provide sheathed products in yellow polyethylene with a black longitudinal stripe. The yellow colour aids in service inspection as damage shows black against the yellow background. The black stripe can highlight any turn introduced into the wire during installation.

3.2.9 Fibre Rope

High strength and high modulus fibre materials offer certain advantages for offshore mooring systems. The use of fibre ropes has increased substantially with the move into deep water and as test results become available. Figure 3-27 illustrates the chronology of the Fibre Rope test programme undertaken as part of the US Deep Star programme.

Figure 3-27 – Chronology of Deep Star Funded Synthetic Mooring Studies –

OTC 12178 [Ref. 14]

Synthetic ropes are made of visco-elastic materials, so their stiffness characteristics are not constant and vary with the duration of load application, the load magnitude, the number of load cycles and the frequency of load cycles [Ref. 15]. In general, synthetic mooring lines become stiffer after a long time in service. Synthetic ropes also creep over time and this needs to be taken account of during design and installation – see for example Figure 6-9.

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3.2.10 Anchoring Options (Drag Anchors, Vertical Uplift Anchors, Piles, Suction Piles)

Drag embedment anchors (see Figure 3-28) are the most popular type of anchoring point available today. This type of anchor has been designed to penetrate into the seabed, either partly or fully. The holding capacity of the drag embedment anchor is generated by the resistance of the soil in front of the anchor. The traditional drag embedment anchor is very well suited for resisting large horizontal loads, but not for large vertical loads.

Drag embedment anchors are generally installed by applying a load somewhere close to the maximum anticipated intact load. At this time the anchor will have penetrated to a certain depth, but will still be capable of further penetration as the ultimate holding capacity of the anchor has not been reached. By this stage the anchor will have travelled a certain horizontal distance, called the drag length. Following installation the anchor is capable of resisting loads equal to the installation load without further penetration and drag. When the installation load is exceeded, the anchor should continue to penetrate and drag until the soil is capable of providing sufficient resistance to match the applied load or drag failure takes place.

Figure 3-28 - Accurate Drag Anchor Placement by Crane in Good Weather Conditions (courtesy of Stolt Offshore)

Vertical load anchors (VLAs) are installed in a similar manner to a conventional drag embedment anchor. During installation the load arrives at an angle of approximately 45° to 50° to the fluke. After triggering the anchor to the normal load position, the load always arrives perpendicular to the fluke. As a VLA is deeply embedded and always loaded in a direction normal to the fluke, the load can be applied in any direction. Consequently the anchor is ideal for taut-leg mooring systems as long as complete embedment is achievable.

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Figure 3-29 Installation and Normal (Vertical) Load Position (courtesy of Vryhof )

Piled anchors (see Figure 3-30) are hollow steel pipes that are installed into the seabed by means of a piling hammer or vibrator. The holding capacity of the pile is generated by the friction of the soil along the pile and lateral soil resistance. It is usually necessary for the pile to be installed at considerable depth below the seabed to obtain the required holding capacity. Piles are capable of resisting both horizontal and vertical loads.

Figure 3-30 Anchor Pile + Chain Tail Deployed by a Twin Crane Construction Vessel (courtesy of Stolt Offshore)

Suction anchors (see Figure 3-31), like piles, tend to be hollow steel pipes, although the diameter of the pipe is much larger than for the pile. The suction anchor is forced into the seabed by means of a pump connected to the top of the pipe, creating a pressure difference. When pressure inside the pipe is lower than outside, the pipe is sucked into the seabed. The pump is then removed following installation. The holding capacity of the suction anchor is generated by the friction of the soil along the length of the pipe and the lateral soil resistance. The anchor is capable of withstanding both horizontal and vertical loads.

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Figure 3-31 Suction Anchor Deployment (courtesy of Stolt Offshore)

In most FPS applications the anchors are semi-permanent fixtures, unlike mobile drilling units where they would be routinely recovered. The forces involved in anchor recovery are high and can lead to damage.

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3.2.11 Line Pull In (Winching) Options

The mechanical design of the line pull in system will influence the design of the mooring system. There are different options which can be adopted. This section briefly reviews the various types and outlines their pros and cons.

Chain Jack

Pros:Powerful mean of

tensioning.

Cons:Slow

manipulation.

Powered Windlass

Most common method for

handling and tensioning

chain.

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Linear Winch

Most applicable in permanent

applications when high tension and

large-diameter wire rope are

required.

Cons:Requires a

large diameter take-up reel to coil the wire rope after it

passes through the linear

winch.

Drum-Type

Winch

Most conventional method used for handling wire rope.

Pros:Operation of a

drum-type winch is fast and smooth.

Cons:1-As the

requirement for line sizes and lengths

increases, the size of the winch can become

impractical. 2-When wire rope is under tension at an outer layer on

the drum, spreading of

preceding layers can

occur causing damage to the

wire rope.

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Traction Winch

The Traction winch has been developed for high tension mooring applications as well as for handling combination mooring systems. It consists of two closely spaced parallel mounted powered drums, which are typically grooved. The wire rope makes several wraps (typically 6 to 8) around the parallel drum assembly. The friction between the wire rope and the drums provides the gripping force for the wire rope. The wire rope is coiled on a take up reel which is required to maintain a nominal level of tension in the wire rope (typically 3%-5% of working tension) to ensure the proper level of friction is maintained between the wire rope and the traction winch. This system has been favoured for use in high tension applications due to the compact size, capability to provide constant torque, and ability to handle very long wire rope without reduced pull capacity [Ref. 16].

Pros:

1-Compact size.

2-Capability to provide constant torque.

-Ability to handle very

long wire rope without

reduced pull capacity.

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3.3 Determination of Minimum Break Load (MBL) & Maximum Stresses

3.3.1 What is MBL and How is it Determined ?

A fundamental characteristic of any mooring component is its minimum break load (MBL). This section discusses the load extension characteristics of typical steel mooring components and reviews how this relates to MBL.

Initially it is helpful to review what happens when a material is loaded up as is seen, for

example, in a tensile test machine (see Figure 3-32). An indicative resulting stress ( )

strain ( ) behaviour and associated terminology are shown in Figure 3-34. Figure 3-33 shows the remains of the chains which were sectioned for material testing in the machine shown in Figure 3-32.

Figure 3-32 - Example of a Tensile Test on a Steel Sample cut out from a Chain Link

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Figure 3-33 - Example of a Chain Sectioned for Material Testing

Figure 3-34 - Example of Terminology during a Tensile Test (courtesy of Ashby & Jones, [Ref. 17])

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Tensile testing will produce a load versus displacement curve which is then converted

to a nominal stress versus nominal strain or n versus n curve where:

n = Force/Area prior to testing (A0)

n = Displacement/Length prior to testing (l0)

The advantage of plotting n versus n is that it allows comparison of specimens with different A0 and l0 on the same graph, thus examing the properties of the material unaffected by speciment size.

The following terminology is illustrated on Figure 3-34:

Y = Yield strength (F/A0 at onset of plactic flow)

0.1% = 0.1% Proof Stress (F/A0 at a permanent strain of 0.1%. 0.2 % proof stress is also sometimes quoted – see also section 14.5. Proof stress is useful for characterising yield of a material which yields gradually and thus does not show a distinct yield point)

TS = Tensile Strength (F/A0 at onset of necking)

f = (Plastic Strain after Fracture or Tensile Ductility. The broken pieces arr put

together and measured and f calculated from (l – l0)/l0, where l is the length of the assembled pieces and l0 is the legth at time 0.

The behaviour past the onset of necking (see Figure 3-34) depends on material characteristics as well as the rate at which the load is applied. Thus the continuation of the curve beyond the maximum load is difficult to obtain, both during tests and in a theoretical analysis of a component. Hence it is of no practical value from the viewpoint of the structural integrity of the mooring system.

Figure 3-35 illustrates how the shape of the stress strain curve will vary depending on material charaterisitics/grade of chain. It can be seen that as strength has increased the strain before fracture has decreased. Brittle fracture was a problem in the early days of developing grade 4 mooring chain in the first half of the 1980’s. However, by carefully controlling the alloy constituents and the quenching and tempering process it is now possible to manufacture a high strength steels, such as R4 or R4S+ (R5), with a grain structure which is more ductile and hence is resistant to brittle fracture. High tempering temperatures may be utilised to optimise Ductility/Toughness Properties.

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Stress Versus Strain Plots for various Chain Grades

0

200

400

600

800

1000

1200

0 2 4 6 8 10 12 14 16 18 20 22

Strain (%)

Str

ess (

N/m

m^

2)

R3 - R3S

R4

R4S+ = R5

Figure 3-35 - Stress Strain Curves for R3, R4 and R5 Chain Steel (Data courtesy of Vicinay)

For a strong, fairly ductile (non brittle) material one potentially has a choice as to what to value to select for MBL. It could either be the load recorded in the test bed when the material fails or it could be the maximum load before the loads drops away prior to breaking. The load recorded at which the material breaks is related to the rate at which the load is applied, so it is somewhat variable. Internation Association of Classification Societies (IACS)W22 [Ref. 66] states: “each sample shall be capable of withstanding the specified break load without fracture and shall not crack in the flash weld. It shall be considered acceptable if the sample is loaded to the specified value and maintained at that load for 30 seconds”. At the end of the break test, in general the tested component should be scrapped.

It can thus be appreciated that manufacturers have to confirm by physical testing that they have achieved the specified MBL and proof load values. In general it would be desirable that sufficient testing should be undertaken to obtain a spread of results. However, since chain is only as strong as its weakest link the minimum value achieved should be considered to be representative of the MBL, not for example the mean or the mean minus a number of standard deviations.

Therefore, the catalogue specified minimum break load (MBL) is actually an agreed specified strength which has an associated testing requirement to ensure that this is achieved. Table 3-10 below indicates the MBL and proof loads for various sizes and grades of chain. The “d” in the expressions refers to the chain diameter in mm.

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Stud Link Studless

Proof Load ORQ KN 0,0140 *d^2*(44-0,08*d)

Minimum Break Load ORQ KN 0,0211 *d^2*(44-0,08*d)

Proof Load ORQ + 10 KN 0,0154 *d^2*(44-0,08*d)

Minimum Break Load ORQ + 10 KN 0,0232 *d^2*(44-0,08*d)

Proof Load ORQ + 20 KN 0,0168 *d^2*(44-0,08*d)

Minimum Break Load ORQ +20 KN 0,0253 *d^2*(44-0,08*d)

Proof Load R3 KN 0,0156 *d^2*(44-0,08*d)

Minimum Break Load R3 KN 0,0223 *d^2*(44-0,08*d)

Proof Load R3 S KN 0,0018 *d^2*(44-0,08*d) 0,0174 *d^2*(44-0,08*d)

Minimum Break Load R3S KN 0,0249 *d^2*(44-0,08*d)

Proof Load R4 KN 0,0216 *d^2*(44-0,08*d) 0,0191 *d^2*(44-0,08*d)

Minimum Break Load R4 KN 0,0274 *d^2*(44-0,08*d)

Proof Load R4S KN 0,02376*d^2*(44-0,08*d) 0,0201 *d^2*(44-0,08*d)

Minimum Break Load R4S KN 0,03014 *d^2*(44-0,08*d)

Proof Load R5 KN 0,0251*d^2*(44-0,08*d) 0,0222 *d^2*(44-0,08*d)

Minimum Break Load R5 KN 0,03186 *d^2*(44-0,08*d)

Table 3-10 - Stipulated MBL and Proof Load Values for Various Sizes and Grades of Chain (courtesy of Vicinay)

3.3.2 Determination of MBL for Worn Mooring Line Components

To be confident that worn components can withstand the maximum estimated mooring loads it is recommended that break testing should be undertaken. Classification Societies define MBL to be the maximum load which the unit can withstand for 30 seconds without failing. However, for worn components it is not possible to know what strength the component should have to begin with. Section 18.8 discusses this subject in some detail.

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3.3.3 Areas of Maximum Stress in a Chain Link

Since chains are fundamental to the majority of long term mooring systems (normally present in the thrash zone and at the fairleads) it is helpful to understand on a loaded chain where the maximum stresses are likely to be experienced. Chain links are complex, statically indeterminate structures subjected to a combination of bending, shear and tension when loaded. Figure 3-36 gives a fairly crude approximation of the stress distribution in a loaded link. Minimum tensile stress occurs in the outside fibres at the intersection of the curved end with the long axis. Maximum shear stress is about

45 away from this axis and on a radial line through the centre of curvature of the end of the link. For chain of low to medium hardness, failure is typically by shear. As hardness increases, the typical failure mode shifts to tension because of bending. The failure location shifts from the maximum shear plane to a plane in the long axis of the link. Combined stresses reduce breaking strength to about two thirds of that computed by assuming that the load is uniformly distributed in simple tension across the two circular cross sections of the straight side of the link. If a link is turned sideways, the long sides of the link are subject to high bending stresses and the load carrying capacity of the link is greatly reduced.

Figure 3-36 – Approximation of the Stress Distribution in a Typical Chain Link

[Ref. 19]

A more accurate determination of stresses in a link or connector can be achieved by undertaking a finite element analysis. Figure 3-37 and Figure 3-38 illustrate typical FE plots for a chain link and a shackle body. Such an FE analysis can consider geometric and material nonlinearities.

From a FE analysis or measurements the value of 1.8P/A in the Crown of the link is found to be 2.1P/A and the value in the weld section changes from 1.8P/A to 1.65P/A. The outer Stresses change from -0.77P/A to 0.02P/A.

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During forging and the flash butt welding residual stresses will be introduced into a link. Such stresses will tend to be minimised during the heat treatment process. However, Vicinay have evaluated the influence of residual stresses created during the proof loading process. During two separate analyses it was found that the effect of the residual stresses were negligible. Still it would be useful to have more data available on the effect of residual stresses – see Section 14.5.

Figure 3-37 - Illustration of a Finite Element Representation of a Chain Link

(Courtesy of Vicinay)

Figure 3-38 – Finite Element Representation of a Shackle Body

(Courtesy of Vicinay)

Linear elastic analyses are performed for fatigue life assessments and non-linear elastic plastic analysis for ultimate load predictions. The behaviour of the components is typically analysed when working under a particular loading boundary condition.

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4 CONTEXT SETTING - HISTORICAL INCIDENTS

AND THEIR SIGNIFICANCE

So far the modern (say post 1995) Floating Production Industry has not made headline news after a spectacular mooring failure resulting in a unit breaking completely free of its moorings and risers. However, a review of some of the more significant mooring failures seen over the last few decades shows that there have been serious incidents in the relatively recent past. Given the substantial increase in the number of FPSs and their increasing age, the probability of a future incident does increase. Hence this section is included to set the context of mooring problems and to try to help to guard

against complacency that technology has advanced to the extent that major failures will

not happen again.

4.1 Long-Term Degradation Mechanisms

Today we have accumulated hundreds of rig years of semi-submersible operating history based on drilling, accommodation and production units. Semi-submersibles have relatively good motion characteristics compared to mono hulls (ships). It will be interesting to see if mono-hull mooring systems suffer from greater degradation compared to semi-sub mooring systems. Overall, it is important that the lessons learnt from semi-subs are transferred to the design of long-term mooring systems. This section attempts to aid in this process.

Figure 4-1 illustrates some of the main loading or degradation mechanisms a long-term moored system must be able to withstand for possibly in excess of 20 years. At the end of this period the mooring system still needs to be able to withstand a 100 year return period survival storm. In general, from an engineering perspective, it is worth considering that there are not many mechanical systems, which after 20 years of hard use can still be expected to meet their original design specification.

B e n d in g & T e n s io n

H ig h e s t T e n s io n s

C o r r o s io n

Im p a c t & A b r a s io n W e a r a n d fa t ig u e

B e n d in g & T e n s io n

H ig h e s t T e n s io n s

C o r r o s io n

Im p a c t & A b r a s io n W e a r a n d fa t ig u e

Figure 4-1 – Illustration of some of the Main Factors which Influence Mooring Integrity

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Some of the most severe conditions occur in the so called “Thrash Zone”, when the chain comes in contact with the sea-bed at the end of the catenary. It is at this point that most cyclic movement occurs and increased stresses may be encountered due to momentum of the moving material. This movement may also cause damage if the sea-bed is hard where the chain contacts it. Another problem resulting from this movement, if the chain is studded, will occur if the studs are able to move. When the studs are loose enough to move freely in the link, then corrosion in the footprint, of both the stud and side of the link will be enhanced due to the fretting action removing the corrosion products and exposing a clean surface. As the process progresses, the rate of corrosion will become higher. This may also be enhanced by crevice corrosion in the early stages” [Ref. 12].

4.1.1 “Argyll Transworld 58” Breakaway

Hamilton’s Argyll development in the UK sector of the North Sea in 1975 was the earliest use of a semi submersible as a production platform – see Figure 4-2. The converted drilling rig “Transworld 58” was renamed “North Sea Pioneer” and was moored in 79 metres of water. Multiple steels risers were used, since at that time flexibles were not considered to be sufficiently developed. The risers had to be pulled during rough weather, which happened 28 times over the first 6 years.

Figure 4-2 - “North Sea Pioneer” on the Argyll Field

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After 6 years on station the “TW58” broke completely away from its moorings. The following description describes the sequence of events that led to the breakaway. The information is taken from a HSE database, in which the identity of the units involved has been deliberately removed.

“In 1981 the converted semi-sub producing from a subsea manifold abandoned production due to the fierceful weather. At 01:19 hrs a 9-ft heave and an 82-knot wind was recorded and the conditions continued to deteriorate and at 02:36 hrs, anchor chain no. 4 parted (tension: 200,000 lbs). Some 20 mins later two other anchor chain parted. Now the rig was 65 to 80 feet off location. At 05:13 hrs anchor chains 6 and 7 parted after the rig had been hit by an unusually large wave. Two helicopters were mobilized. The weather continued to build and 20 mins later the breakaway of the rig appeared imminent and anchor chains 10, 11 and 12 were cut. This action was taken to prevent the overrun of these anchors and possible capsizing of the rig as a result. Only anchor chain no. 1 was left dragging. This prevented the rig to drift directly towards the sbm. The rig's mat tanks scraped over but cleared the <...>'s mooring lines. Once clear of the <...> The evacuation could start. 48 persons were evacuated while 22 remained onboard. The rig continued to drift another 1.5 days before being secured by a towline. The rig had drifted some 27 miles from original position. The rig was towed to <...> for inspections and replacement of anchor chains.”

The breakaway of a production semi submersible with a wire mooring system may not seem too relevant to most modern custom designed FPSOs. However, the fact that conditions developed which caused a multiple line failure is reasonably significant in itself. For the “TW58” it was extremely beneficial that the steel risers were designed to be disconnected in severe weather. This is not the normal situation for as FPS with flexible risers. Hence, if all the moorings fail on a FPSO which has no dynamic positioning assistance, the likelihood is that the risers would all be ripped out at either at the sea-bed or the vessel, or a mixture of the two - see also Section 5.3.

4.1.2 Points of Significance

In summary, the key issues, from an up date perspective, to note from this incident are as follows:

1. Single line failure followed by multiple line failure led to a complete loss of station.

2. There was a potential danger of capsize which was prevented by cutting the remaining mooring lines, which fortunately in this instance, were accessible from the deck.

3. Subsea damage was likely from a dragged chain and anchor.

4. High potential loss of life.

5. Extended period of deferred production.

6. High collision danger with neighbouring facilities.

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4.1.3 Fulmar SALM Breakaway

The first Floating Storage Unit (FSU) in the North Sea was installed at Shell’s Fulmar field in 1981. The converted 210,658 dwt “Medora” was yoked by the bows to an articulated Single Anchor Leg Mooring (SALM) – see Figure 4-3 and Figure 4-4.

Due to fatigue cracking the Fulmar SALM broke free at wedges at the base of the mooring column in 1988, after 7 years on station. Weather conditions at the time, although severe, were below the mooring survival design criteria. The Fulmar SALM breakaway made headlines news as can be seen from the extract from the BBC in Figure 4-5.

At one stage the Fulmar SALM was freely drifting in the North Sea with the anchor column nodding up and down as the ship tracked across the sea-bed. It is understood that the 3,700 tonne mooring column made tracks in the sea-bed every time it came in contact with it. Apparently the column made a seabed depressions each side of the Forties pipeline, but fortunately did not hit it!

Figure 4-3 – Fulmar SALM after Breakaway (courtesy of BBC film clip)

Although the Fulmar SALM is an unusual design, it does have basic similarities to present day turret moored FPSO. The damage it could have caused if it had collided with other oil and gas installations while it was freely drifting can be imagined.

The time on station for both the TW58 (6 years) and the Fulmar SALM (7 years) before problems occurred roughly ties in with the statistics reported in Noble Denton’s UKOOA report. Overall both incidents illustrate the importance of not being complacent about mooring integrity as systems age.

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Figure 4-4 – Schematic of the layout of the Fulmar SALM

4.1.4 Points of Significance

The key issues, from an up date perspective, to note from the Fulmar breakaway are as follows:

1. A fatigue failure in the detailed design of a connecting element.

2. A long-term degradation mechanism was involved.

3. The BBC reporting probably led to some reputation damage.

4. There was potential huge subsea damage and pollution damage.

5. There was a real collision risk with neighbouring facilities.

6. An extended period of deferred production resulted in which the complete FSU was replaced by another vessel.

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Figure 4-5 - Extract from “On this Day” BBC Website

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4.1.5 Weathervaning Navigational Lightships

Weathervaning lightships have been riding out the worst of winter storms since 1732 [Ref. 20]. Lightships have to stay on station whatever the weather and only rarely come into port for repairs. Figure 4-6 illustrates a typical lightship mooring. Although lightships are much smaller than FPSOs, it can still be informative to learn from the considerable SPM mooring experience they have accumulated over many, many years.

Figure 4-6 – Illustration of a Typical Lightship Weathervaning Mooring(courtesy of “No Port in a Storm” [Ref. 20]

On Lightships it was well known that the most vulnerable point for a mooring line was where it left the ship, otherwise known as the “nip.” Here a length of canvas was wrapped around the chain to reduce wear upon it (see also the CALM buoy rubber bung on Figure 9-19). Thus the line length was regularly adjusted to minimise wear at the “nip”. Also swivels were introduced in the mooring line to reduce the chance of the cable knotting or kinking.

Figure 4-7 shows the “North Carr” Lightship, which broke free from her moorings in 1959 and was free drifting while fully manned. This failure led to an ultimately tragic rescue operation. The left hand side of Figure 4-7 shows the links that failed in the grounded line section. The right hand side shows a link that failed on a North Sea FPSO in 1999. As can be seen, there is a certain similarity between the two failure mechanisms.

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Interestingly a certain number lightship mooring failures did not occur at the height of a storm, but a short period after the worst weather had passed. A similar behaviour has been noted for mooring line failures on semi-submersible rigs.

It is significant that most British lightships were not equipped with any form of propulsion and hence were at the mercy of the waves if they broke free. Many FPSOs also do not have any form of propulsion and thus would be unable to steer out of trouble if they should break free. Although the likelihood of a FPSO totally breaking free is low, if it should happen the consequences of a collision could be extremely severe. Since thrusters can help stabilize offloading operations and can help process equipment motions by adjusting FPSO heading, it can be argued that there are three good safety reasons for specifying their inclusion on FPSO projects from the outset.

Even in recent times lightship “moorings fail with depressing regularity,” see Figure 4-9). Hence, all mariners on Light Ships “live with the perpetual fear that the moorings might fail” and thus take appropriate safety precautions. It would be highly desirable if this mariner watchfulness about the integrity of moorings could be more widely distributed.

Figure 4-7 - Helicopter Rescue from the Free Drifting “North Carr” Lightship after Mooring Failure [Ref. 20]

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Figure 4-8 - Illustration of the North Carr Link Failure Relative to a 1999 North Sea FPSO Link Failure (fatigue cracking followed by ductile rip out)

Figure 4-9 - Dutch Lightship Number 11 whose Mooring Failed in a Force 10 Gale in October 1991 which also broke a number of semi-sub moorings – see Section 4.2

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4.2 Multiple Line Failure Incidents

Mooring systems are typically analyzed to check that station keeping can be maintained in case of one line failure. Thus, it is tempting to conclude that multiple line failure scarcely ever occurs. However, studying the literature reveals that this is not necessarily the case. For example, during storms in October 1991 and January 1992 there were 8 semi submersible mooring incidents, of which 3 were multiple failures, two double and one quadruple. The quadruple failure resulted in the vessel having to abandon its location. There were so many incidents in these two storms that the HSE commissioned a special investigation report, OTO 92 013 [Ref. 21].

In both storms adequate warning was provided in weather forecasts available to all rigs. Both storms were less severe than the design storm, although in the case of the January storm which affected northerly areas most strongly, only marginally so. It is interesting to see that semi subs were not alone in suffering during these storms, Figure 4-9 shows a weathervaning lightship whose mooring also failed and the vessel ran aground.

Given the moorings lessons learnt over the years it might be expected that a semi submersible which was upgraded in 1997 and was fitted with new mooring lines would not be subject to multiple line failures. However, this was not the case for the Bideford Dolphin which in 2000 lost three moorings lines during a storm in the Snorre field.

Coming even more up to date in December 2004 the “Ocean Vanguard” semi-submersible lost two of its eight anchor chains and had its riser torn off when drilling for Eni Norge on Haltenbanken in Norway. The wind was reported to be 43 to 60 knots and the waves were approximately 17 to 18m in the area where the incident took place. In this instance it is believed that it was not a mooring line failure but instead the pawls which lock off the winch failed. This illustrates the key point that all arrangements for stopping off the chain including connections should be strong enough and able to tolerate fatigue loading over the life of the field and beyond, if re-deployed, which is likely with a FPS.

4.2.1 Gulf of Mexico Experience

Incidents of multiple mooring line failures are relatively common in the Gulf of Mexico during hurricanes [see Ref. 22]. This paper reports that during hurricane Lili the semi “Ocean Lexington” broke her moorings and drifted to the beach. In the same storm the semi “Glomar Celtic Sea” lost 6 out of 8 of its mooring lines.

In 2003 Typhoon Fay in SE Asia is believed to have caused damage to some of the Venture series FPSOs, but details have been hard to obtain.

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Hurricane Ivan, which passed through the Gulf of Mexico in September 2004, is reported to have left the following in its wake:

5 Mobile Offshore Drilling Units (MODU) were adrift.

One MODU was reported to be leaning about 3 degrees

The 5th generation “Deepwater Nautilus” semi (see Figure 4-10) broke all her moorings and drifted 120 kilometres north-east from its pre-storm location. It is understood that the Rig had a composite fibre rope and steel mooring system. Full details of the failure are, unfortunately, not in the public domain, but it is understood that all the failures occurred in the steel wires not the fibre rope. The steel wires were of 3¾” (95mm) diameter and each line was designed to withstand a force of 693t (6,800kN or 1,500kips)

Figure 4-10 - Fifth Generation “Deepwater Nautilus” Broke free of all her Moorings during Hurricane Ivan

Results to date indicate that hurricane Ivan did not cause any damage to the mooring systems of the permanently moored Spars and production semi submersibles in the Gulf of Mexico. It would, however, be interesting to follow the track of Hurricane Ivan and to see how close it came to any of the permanent mooring systems. It is also worth noting that the majority of long-term mooring systems in the Gulf of Mexico are still relatively new and thus fatigue, corrosion and wear effects will not yet have fully developed.

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4.3 “Petrojarl 1” Multiple Lines Failure (1994)

The “Petrojarl 1” FPSO (see Figure 4-11) experienced multiple line failures while working on the Hudson Field approximately 60 miles north-east of the Lerwick in the Shetland Islands in January 1994. “Petrojarl 1” was subject to 50 to 55 knot NW winds and lost two lines at the same time after being hit by a 20 to 25m high wave. Overall 4 out of 8 lines broke over an 8 hour period (lines no. 2, 3, 4 and 7 parted). After the initial failure production was shut down and the vessel kept on station using her thrusters and the remaining mooring lines. “Petrojarl 1” was never off station and started reconnecting mooring lines the next day, personnel were not evacuated. It is worth noting that “Petrojarl 1” had the option of quick disconnection of the remaining mooring lines and risers [Ref. 23]. Planned riser disconnection is not possible for the majority of FPSOs, apart from those designed to operate in areas subject to ice bergs or typhoons.

Figure 4-11 - “Petrojarl 1” which experienced two broken lines at the same time when hit by a steep wave

4.3.1 Points of Significance

The key issues, from an up date perspective, to note from this incident are as follows:

1. There was double line failure when hit by a smaller than the design wave.

2. The presence of thrusters prevented an uncontrolled break away.

3. The multiple failures were due to fatigue damage which developed at around about the same time to a number of mooring lines.

4. Unusually this particular type of turret design allowed rapid identification that a line failure had occurred.

4.3.2 Overall Message from the Case Studies

Even during the course of this JIP mooring failures have continued to occur both in the North Sea and also in the Gulf of Mexico. Other case studies are covered through out the remainder of this report. In general it is clear that a great deal can be learnt from the case studies which it is believed is highly likely to be relevant to many of the FPS units operational in the world at the present time.

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5 CONSEQUENCES OF MOORING LINE FAILURE

5.1 Single Line Failure

As discussed in chapter four, there have been several examples of single line failures on moored floating offshore structures in the history of the industry. Experience has shown that line breakages are not restricted to extreme sea-states. Failures have occurred in both moderate and severe conditions, although the failures in moderate conditions tend to follow on fairly quickly from storm loading.

Various sources of potential failure have been identified, namely:

Overload/overstress

Fatigue in a catenary, at a sheave or connection

Brittle fracture

Corrosion

Wear and abrasion

Mechanical failure of the mooring line handling/lock off system

In many cases several of the above will interact, for example fatigue damage at a sheave followed by overload of the remaining ligament under storm conditions. A potential failure scenario is illustrated overleaf in Figure 5-1.

Although, at present, there are no fixed regulatory requirements for the timescale under which damaged lines should be replaced, the continued operation of a unit with one damaged mooring line should lead to re-appraisal of the reduced mooring system using the higher intact condition safety factors. Where the full design condition cannot be achieved, consideration should be given to reduced operating conditions. In fact, in the era of uncertainty following a line failure, it can be argued that the safety factors on the remaining lines should be raised until it has been determined with reasonable confidence why the original line failed.

Revised operating conditions could be identified prior to loss of a line, permitting a more rapid assessment of the damaged condition. It is recommended that a summary of reduced environmental parameters for production should be available on board alloperating FPSs in case of line failure.

This single line failure condition falls within the normal design criteria for the mooring system and should not threaten the integrity of the unit directly. Under certain conditions the falling chain could damage sub sea infrastructure. For example, a flexible could be swept below mooring lines under high current conditions, exposing it to impact. This could be of most concern to a gas riser and should be considered as part of the detailed design process.

For specific units in deep water hydrocarbon conditions could cause riser blockage due hydrate or waxing in case of an extended shutdown. If a unit from a process point of view cannot tolerate shut down, it will be cost effective in the long-run to add in additional contingency in the mooring system. This should be specified in the design brief, see Section 20.

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Deterioration

The progressive deterioration of a component of the system under fatigue,

corrosion or wear.

Failure Followed by failure of the component under moderate storm conditions.

Detection

Line loss might be detected through tension monitoring equipment where that is

installed. It is possible that the line failure could be undetected until a routine subsea

check of the mooring system.

Shutdown

The system is likely to be shutdown until the continued integrity of the mooring

system has been verified and new operating limits defined.

Inspection

The mooring and production systems would be inspected to identify any related

damage.

Reduced operations Resumption of operations under

reduced weather criteria.

Repair Reinstatement of the full mooring system.

Figure 5-1 - Summary of a Single Line Failure Scenario

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5.2 Multiple Line Failure

The failure of several mooring lines could overload remaining lines in sequence, resulting in loss of position of the unit. Multiple failures in the mooring system are ranked as safety critical risk category 1 which is the highest category [Ref. 23].

Y

Z20 m

g_ g _ _ _ _ _ q _ _ j _ ( ) ( ; ) p

Figure 5-2 – Illustration of Riser “Stretch” After Loss of Position Following Mooring Line Failure

There have been several instances of multiple line failure of a fixed floating unit. Factors which contribute to the likelihood of multiple (as opposed to single) line failure include the following:

Design: the presence of a systematic weakness in the mooring system will apply to all lines, increasing the likelihood of multiple line failure.

Age: fatigue, corrosion and wear will tend to deteriorate all mooring lines, particularly in the same quadrant, to roughly the same extent over time.

Detection: where no line tension or equivalent monitoring system is available, failure of a single line may go undetected (see Figure 5-4). This may expose the remaining lines to higher loads for an extended period.

Mooring system technology continues to change as operations move into deeper water and new techniques are developed for more marginal fields. The extension beyond proven technology can introduce unexpected problems. As the existing fleet ages, fatigue, wear and corrosion will become more significant, again exposing any design weaknesses in the mooring systems.

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A potential multiple line failure scenario is illustrated in Figure 5-3. Figure 5-4 illustrates how prompt detection of line failure and good quality inspections can reduce the danger of multiple line failure.

Figure 5-3 - Potential Multiple Line Failure Scenario

Deterioration The progressive deterioration of a type of

component under fatigue, corrosion or wear.

1st Failure Followed by failure of the component

under moderate storm conditions. This could go undetected

Unzipping Overload of adjacent lines, perhaps after further deterioration if the initial failure

was undetected.

Excursion Loss of integrity of the mooring system could be identified from the loss of station

keeping after failure of several lines.

The risers should be de-pressurized and isolated prior to damaging distortions in the

system.

Shutdown

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In the event of some combination of circumstances leading to rupture of a riser without depressurisation, for instance where initial mooring line loss was undetected; the rate of gas / oil escape would be much larger. Rupture at the base of the turret could result in a significant release of gas or oil close to the FPSO. If the unit is still producing and sources of ignition such as the flare are lit, a gas explosion could result. This illustrates the importance of early detection of mooring line failure. It is also conceivable that wave grouping and rogue waves might cause multiple line failures to an intact system if it is under designed or if the integrity of lines from a particular sector has been compromised by wear, corrosion and fatigue. “Petrojarl 1” appears to have lost two lines at the same time when she was struck by a large wave in 1994, see Section 4.3.

The formation of a large gas bubble underneath the FPSO itself could potentially affect the stability of the whole unit.

5.4 Business Interruption Consequences - Two Case Studies

Clearly the commercial impact of shutting down production and repairing the mooring system would depend upon both production rates and the extent of damage.

Scenario 1 Medium Sized North Sea FPSO producing 50,000bpd

This scenario assumes the following after 7 years on station:

Loss of one mooring line and as a result shutting down for 2 days to identify the extent of the damage

Dive Support Vessel (DSV) mobilisation to survey subsea infrastructure (risers, condition of remaining lines, etc.) and to support the line repair

Mobilisation of 2 x anchor handler tugs (AHTs) to reinstate the damaged line plus a FPSO heading control tug.

An indicative costing for the above incident has been worked out inTable 5-1. Note it is assumed that suitable spares, including connectors, are available. Hence the capital cost of spares and replacements has not been included.

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Item Calculation Value Notes

Deferred Prdn 2 x 50,000

x $25 £1,470,000 Assuming 1.7$ to £1

DSV(2+2) x £70,000 £280,000

Heading control tug

(2+2) x £15,000 £60,000

2 days mob / demob

AHTs2 x (2+2) x

£15,000 £120,000 plus 2 days

diving

Total £1,930,000

£2M

Table 5-1 - Line Failure Cost Estimate, 50,00bpd North Sea FPSO

The $25 per barrel rate for oil is based on deferred production cost and will be field specific depending on operating costs, etc. It has been estimated using the following typical formula:

Value of deferred production = Deferred volume x Margin x Discount factor

The following terminology applies:

Margin = the prevailing oil price less the production facilities cost of delivery including all appropriate costs (depreciation, variable lifting and transportation costs, etc.)

Discount factor = 1/(1+discount rate)n

The Discount rate has been taken to be the fairly industry standard level of 10% and “n” is the period in years.

If one assumes that the present oil price is about $45/barrel and that the lifting or recovery cost is approximately $10/barrel, the price per barrel of the deferred production in “n” years time is as follows:

Deferred production cost ($/barrel) = (45 – 10) x 1/(1.1n)

Hence, if a line failure occurs in year 7 and the anticipated field life is 20 years the calculation becomes:

Deferred production cost in 20 years = 35 x 1/(1.120-7) $10/barrel

Value of product today $45 - $10 = $35/barrel

Lost value in deferring production $35 - $10 = $25/barrel

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Scenario 2 Large West African FPSO Producing 250,000bpd

This scenario assumes the following:

Loss of one mooring line and as a result shutting down for 2 days to identify the extent of damage

DSV mobilisation to survey subsea infrastructure (risers, condition of remaining lines, etc.) and support line repair.

Mobilisation of 2 x anchor handling tugs to reinstate the damaged line. It is assumed that the unit is spread rather than turret moored and hence a heading control tug is not required.

An indicative costing for the above incident has been worked out Table 5-2. Again it is assumed that suitable spares including connectors are available. Hence, the capital cost of spares and replacements has not been included. It is worth noting that the mobilisation time and costs are significantly higher for a West African FPSO than for a North Sea FPSO. In practice it may be the case that suitable vessels are available locally, but this cannot be relied upon.

Item Calculation Value Notes

Deferred Prdn 2 x 250,000 x $25 £7,353,000 Assuming 1.7$ to £

DSV (30+2) x £70,000 £2,240,000 30 days mob / demob

AHTs 2 x (30+2) x £15,000

£960,000 plus 2 days diving/repair operation

Total £10.5M

Table 5-2 - Line failure Cost Estimate, 250,000bpd West African FPSO

Two simple conclusions can be drawn from the above calculations.

Financial costs associated with mooring line failure are large, particularly relative to the capital cost of the failed component.

Both lost production and vessel costs are significant.

Where the platform is remote from the main offshore operating centres, deployment of suitable vessels may take several weeks. If the integrity of FPSO or subsea infrastructure after the incident cannot be demonstrated using local resources, a lengthy shutdown may be required. A long shut down would increase the cost of deferred production dramatically.

Repair of the system may require the procurement of special connectors or replacement line segments. These may have lead times of 4 to 6 months, requiring medium term operation either with one line down or a short term connector solution – see Section 19 on contingency procedures and spares. The cost of the repair will increase if two repair mobilisations are required, in other words an initial short term fix followed by the long term repair.

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6 HANDLING, TRANSPORTATION/TRANSFER AND

INSTALLATION

6.1 Transportation/Transfer

Mooring lines are not simple items to transport due to their length and weight. Any damage to lines during transportation of transfer can have serious implications for long-term mooring integrity. Manufacturers typically have detailed instructions for transportation and transfer of their products and these instructions should be followed to the letter. Poor practice during transportation and handling potentially can destroy project schedules.

Figure 6-1 gives a good indication of the great care needed while handling fibre ropes with careful level winding and proper back tension when the ropes are installed on the reels.

During transportation, transfer to installation spools and installation of sheathed wire rope, particular care must be taken to ensure that sheathing remains undamaged.

Figure 6-1 - Spooling Fibre rope onto a Powered Reel from Standard Containers[Ref. 24]

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6.2 INSTALLATION OF MOORING LINES AND CONNECTORS

The installation procedures for FPS moorings are highly dependent upon the design of the system, the water depth and the available installation vessels. There are several issues in the deployment of FPS mooring lines additional to those encountered with mobile offshore units.

A FPS mooring system must operate continuously with restricted inspection and maintenance over a long period. Installation damage to protective sheathing, connectors and mooring lines can cause fatigue and corrosion problems over time.

Many FPS units operate in deep water locations. As a result a complex line make-up including wire rope, man made fibre segments and occasionally mid line buoys may result.

The FPS requirement for the mooring system to support extreme conditions without moving off station can lead to large heavy mooring system components (Figure 6-2 gives an indication of the manual handling issues). It is clear that items such as bend stiffeners can be relatively easily damaged. This has been seen on recovery of a North Sea FPSO mooring system at the end of a relatively short deployment – see Figure 6-6.

Figure 6-2 - Illustration of the Weight and Handling Issues Associated with Mooring Components (Courtesy of Stolt Offshore)

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6.2.1 “Dog Leg” or Wavy Mooring Lines on the Seabed

During mooring line installation it is important that all lines should be laid straight from the anchor to the fairlead at the no load equilibrium position. This requirement should be emphasized in the installation procedures and reflected in any tug specifications. If “dog legs” or wavy lines do end up being present, and they are pulled out by storm loading, this can lead to unbalanced mooring line tensions. In other words a system which was balanced originally with the “dog legs” may no longer be so. If one line takes more of the load coming in from a particular quadrant it is more likely to fail. If this originally taut line fails, the FPS may exceed its allowable riser offset limit if the remaining lines are too slack.

To date non-straight mooring lines have been noted on two North Sea FPSOs – see for example Figure 6-3. On these units the initial pre-tensioning operation and the storm loadings which have been experienced have been insufficient to overcome the friction of the lines in the sea-bed mud. However, so far, these FPSOs have not yet experienced storm line loadings as severe as the maximum loadings evaluated during the mooring design process. Analysis results indicate that with a tension of 500 tonnes it will not be possible to drag a dog legged mooring line through the mud. This seems to tie in with what happened offshore during pre-tensioning. However, it should be noted that this is an area of uncertainty, since there is a lack of data to assist with, for example, selection of axial and normal drag coefficients.

Figure 6-3 - Red Arrows Show Examples of Mooring “Dog-Legs”

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It will be interesting to see if, over the respective field lives, the “dog legs”/wavy lines are pulled straight or not, and this should be monitored during annual ROV surveys. If straightening occurs the implications for mooring line tensions and fatigue loading should be re-evaluated. If Dog Legs are still present at the end of the field life, this could indicate some conservatism in the design process, particularly if during this time the FPSs have experienced survival conditions.

6.2.2 Torque Implications for Mooring Line Installation

The design of a mooring system requires consideration of the potential for torsion in the lines. This includes the behaviour of each component with respect to imposed tension and torsion. Hence, during the installation of heavy components in a chain or spiral strand system, consideration must be given to the introduction and control of torque.

Application of tension to a wire rope will tend to straighten the individual rope fibres, resulting in either rotation or a corresponding restraining torque. The torque developed is approximately proportional to applied tension and wire rope diameter. For an ordinary lay six strand steel independent wire rope core (IWRC), Bridon Ropes quote the following expression for torque developed under tension.

TensionDiameterTorque 07.0

More complete expressions, taking into account twisting of the rope, the increased torsional stiffness of rope under tension and even cross terms between these various components are given by Chaplin [Ref. 25]. The simplest of these expressions is given below.

2

24

000,75

187.0000531.0

085.0

mm

NewtonG

DiameterTensionDiameterGAwhere

Length

RotationATensionDiameterTorque

The first term is equivalent to the coefficient presented by Bridon. The coefficient on rotation represents the geometric torsional stiffness of the wire rope, plus an additional term reflecting interaction between tension and torsional stiffness.

It should be noted that the numerical coefficients listed above vary even within the reference quoted above, and as such predictions of the numbers of turns for a given condition should be treated with care.

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The four different types of line segment used in the deployment and operation of mooring lines exhibit very different torsional characteristics. Both the torsional stiffness and the tension induced torque vary.

Six (or eight) strand wire rope is not torque balanced. This means than when an axial tension is applied, torsion is developed in the line. The greater the tension, the larger the torsion.

Chain demonstrates little torsional stiffness for low levels of rotation, very high stiffness for greater rotation (in excess of 3 degrees per link). A chain with no twist will not develop torsional moments under tension.

Spiral strand wire rope presents a relatively high torsional stiffness. It is “essentially torque balanced”, developing a much reduced torsional moment than the corresponding six strand rope. If a torque is applied to spiral strand wire it can easily become damaged – see Figure 6-7.

Polyester rope has a low torsional stiffness, due to the small diameter of individual fibres. There is little tendency to develop torsional moments under tension.

In the design of mooring systems, consideration must be given both to the interaction of the individual components in the operating condition, and to the implications of this during installation. It is very important when deploying chain that no twists should be included, but in practical terms for a long length of chain this is not simple to achieve in practice.

Clearly, where one component has a tendency to rotate and develop line torsion, this may result in the twisting of adjacent components. Each line type has different issues associated with the imposition / release of torsional loading.

Where six or eight strand wire rope is subjected to dynamic axial loads with no torsional restraint it will rotate. The combination of tension and rotation is much more subject to fatigue than tension cycling with ends restrained. There may also be issues associated with the “whirling” of heavy fittings or adjacent chain segments increasing damage rates.

The performance of chain when subjected to torsion plus tension is not well understood. Where line tension drops below a limiting value there is some possibility of knotting of the chain, which will reduce strength and fatigue resistance. Under significant tensions chain is able to accept small levels of rotation without apparent damage.

Spiral strand wire rope is both relatively stiff in torsion and sensitive to damage when twisted. This damage occurs due to slippage between layers of (torque balanced) wire. In extreme cases this can develop into “hockles”, where the lay of the wire is so distorted that some wires twisrt right away from the body of the rope – see Figure 6-5 and Figure 6-7).

Fibre ropes appear to be able to accept quite large levels of rotation without a significant impact on their performance.

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Figure 6-4 - Illustration of Twist on a FPSO Mooring Line during Recovery

Figure 6-5 – Illustration of a “Hockle” in Spiral Strand Wire during Recovery of a FPSO Mooring System

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Figure 6-6 - Example of Damage to the Bend Stiffener on an Open Socket

Figure 6-7 – Illustration of Spiral Strand Wire Kinking during Installation

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6.2.3 The Use of Swivels

Where it is desirable to prevent the imposition of torque on mooring line segments, in line swivels may be used. There are two main types of offshore mooring swivel. Slide bearings provide a robust, low maintenance torque release, but will only operate under quite high torque levels. Roller bearing swivels provide a low friction torque release, but require maintenance.

Swivels are sometimes used during the installation of deepwater moorings to avoid the introduction of twist in a heavy chain or spiral strand line segment.

If a mid-line buoy is to be used in a mooring line, a connection link such as that illustrated in Figure 6-8 may be used. This connector allows the central section which is attached to the buoy to rotate but the padeyes on either side for the main mooring legs are fixed relative to each other. This type of swivel is intended more for use in a permanent mooring system as opposed to as a temporary installation measure.

Figure 6-8 - Mid Line Buoy Swivel Connection Link (courtesy of MoorLink AB).

Mid line buoys can result in greater relative rotation at the connections which in certain instances has been known to lead to premature failure – see Section 10.3.2. Therefore, the use of mid line buoys should be treated with caution.

6.2.4 Pre-Installing Mooring Lines

It is often desirable to pre-lay mooring lines. This permits location and securing of anchor points prior to the arrival of the FPS. Separation of the installation programme into discrete segments reduces the vulnerability of the programme to weather windows and removes these operations from the critical path.

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Deploying an anchor pile, chain, spiral strand wire or polyester rope as one operation can be problematic, unless a high specification construction vessel is employed and great care is taken. Potential difficulties include:

Risk of rotation, possible interference and damage

Difficult to control simultaneous lowering of multiple handling systems

Difficult to reverse the process.

However, a reliable subsea connector is required if lines are going to be pre-installed. If the subsea connector is not reliable, over time a weakness may be introduced into the system. Assuming a reliable subsea connector is available its use may help with respect to possible mooring line repair operations which may be needed at some stage during the field life. It is important, to minimise relative rotation and wear, that the weight per metre of the connector should not be too much higher than that of the mooring line to which it attached.

6.3 Installation Watch Points from a Mooring Integrity Standpoint

Over the last few years there have been a number of notable deepwater projects completed in the Gulf of Mexico, which have used either spiral strand wire or fibre ropes. Very useful experience has been gained form these projects. This section attempts to summarise some of the key lessons learnt.

Suction Pile Rotations

It is important that the orientation of the padeye lines up with the mooring line direction when it is tightened up. Cases have been reported of suction piles rotating as they are sucked into the sea-bed, which can be problematic.

Spiral Strand Wire

The key watch points are:

Requires handling within tight tolerances for twist, friction and compression.

Sheathing can be easily damaged.

There have been several cases where spiral strand has been irretrievably damaged (usually through kinking) during installation.

Polyester / Synthetic

The key watch points are:

Large diameter ropes, have a large storage volume requirement.

Multiple spooling operations from storage reels to installation winch are normally required.

The outer braiding layers are susceptible to damage.

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“Although polyester is a durable material, the braided jacket and even the core, can be subject to damage during installation if not properly handled, much like sheathed spiral strand wire” [Ref. 26].

At present it is customary not to allow polyester rope to come in contact with the sea floor due to concern that particle ingression will cause harmful abrasion of the fibres. With the introduction of “soil particle filter clothes just under the jacket this may be no longer necessary [Ref. 26] but at present it is customary to adhere to and this will impact the installation procedures.” Balmoral Group Norway’s experience with MODUs and fibre ropes indicates that this may not be required. However, it is still difficult to know what would happen during a true long-term deployment.

Installation Ground Rules

It can be helpful to provide Installation Contractor with “succinct ground rules” for installation including any special considerations, e.g. handling of polyester ropes, such as:

Limits on twist

No sea-bed contact

Acceptable means to handle and stopper

Temporary storage and transport requirements

Contingency measures

Past projects have successfully utilised a “management of twist procedure” to identify how twist will be monitored, assessed, recorded and summed up over a mooring line. In particular, it is important to specify low torque or torque balanced wires for messenger line or slings during installation. Twist can be monitored by a ROV viewing a pre-painted stripe onto the mooring chain and a colour stripe marker built into the polyester ropes jacket during the manufacturing process.”

Petruska reports [Ref. 26] “Installing a polyester mooring system is similar in many ways to installing a sheathed, spiral strand wire system when using similar/identical installation vessels, but a few differences do exist. For example sheathed, spiral strand has special requirements on minimum bending radius and the associated tension in order to prevent damage to the sheathing and also to prevent kinking wire strands. Both have limitations on twist, although different, since spiral strand is not perfectly torque balanced while polyester ropes can be made to be torque neutral. On the Mad Dog project two complete twists (i.e. 720º) per mooring line were permitted for the fibre rope.”

Although polyester weighs much less both in air and in water, it does take up more volume, which needs to be taken account of during installation.

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6.3.1 Polyester Rope Line Length Implications

Polyester rope lengths can vary and it is important to understand the different categorisations namely:

Manufactured length,

Installed length at the specified pre-tension,

Lengths expected at various phases during the installation.

The total variation through out this process may vary as much as 50 to 100m. Short Term Creep and Long Term Construction Stretch may lead to a need for the rope being manufactured somewhat shorter than its final required length.

Common practice calls for polyester to never come into contact with sharp edges, high heat or steel work wires. It is vital to ensure all equipment free of sharp edges and where necessary to use special padding material such as “burlap” or “lamiflex” to further aid in protecting the rope jacket from snags and tears.

On fibre rope moorings the majority of fibre rope creep should occur in the first year of service. This creep is likely to result in a requirement to re-tension the mooring system. On the Red Hawk Spar there is no requirement for spar offsetting for well drilling or maintenance operations. Hence a single chain windlass located at one position on the Spar deck with fairleading access to the six mooring stations was assessed to be sufficient for pre-tensioning and mooring line adjustment purposes if required. This single chain windlass was integrated into the topsides rather than at a dedicated winching deck as on previous spars. To reduce the necessity of future line length adjustments, some of the fabrication stretch was removed as illustrated below. This required application of a tension level of 40% of the MBL for 1 hour, namely approximately 500 t. The geometric amplification provided by this means seems to be capable of achieving such a tension. It appears that this method of tensioning up the lines is not very precise and there must be a danger of increased dynamic loading of the tensioning tow line due to tug motion/changes in tow line angle. Hence it will be interesting to see how such lines perform in situ.

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Figure 6-9 – Pre-Stretching Polyester lines During Installation to Minimise the Requirement for Future Line Length Adjustments [Ref. 27]

Fibre Rope Protection

It is important to limit fibre rope exposure to ultraviolet light by the use of lamiflex sheeting and tarpaulins. Also there should be no welding or flame cutting in the vicinity of fibre rope. Hence there may be a need for bolted clips for sea fastening the rope reels to transportation cradles.

Fibre Rope Connectors and Thimbles

The design of connectors for use with fibre ropes is still evolving. Figure 6-10 illustrates one design that has been used in the Gulf of Mexico.

Such connectors need to be designed to simplify offshore lining up of pins. For example in Figure 6-10 the H-link is not a true H-link in the sense that the two face plates are not rigidly connected. This allows differential movement of the two plates which can cause problems with alignment and getting the pin back through especially at the hang-off platform under load” see Figure 6-10.

The illustrated design includes a thimble which “should” take most of the wear. But “tight fits may still be encountered offshore, since the polyurethane protective coating around the eye of the polyester splice is manually applied. Also when spreading the eye of the polyester splice to insert the thimble, tearing of the polyurethane would often occur in the crotch region, thus either special care/an improved procedure is required or the polyurethane needs to be reinforced.

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Not all fibre rope connectors have made use of thimbles so it will be interesting to see if over time wear/abrasions becomes an issue. Unfortunately inspection access to this area is difficult – see Section 18.6.1/Figure 18-15.

An important point for the use of fibre ropes is careful labelling for identifying/avoiding confusion on fibre rope segments.

Figure 6-10 - Illustration of the Potential Difficulty in offshore alignment of pins on large Diameter Rope [Ref. 26]

6.3.2 Overboarding Operations

Overboarding of heavy items (anchors, sockets, etc.) may need special protection as may be provided by a sledge arrangement – see Figure 6-11 for example which shows an ‘H’ shackle launch. The sledge can be recovered using a work wire on to a capstan winch after the heavy item has been deployed over the stern roller.

Figure 6-11 - Sledge used to Protect “H” Connector during Deployment over the Stern Roller (Courtesy I. Williams)

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6.3.3 Anchors

Once anchors have been installed and successfully pre-tensioned on FPSs they seem to have proved reliable in situ. The difficulties which have been experienced in the field are typically when soil conditions turn about to be different than predicted. Hence, it is desirable to collect sufficient soils information prior to the FPS deployment.

If project schedule and vessel availability allow, it is recommended that the following site survey work should be undertaken prior to installation:

Carry out bore hole soil sampling at two locations on each mooring line.

The first location should be the anticipated anchor landing point.

The second location should be the predicted final anchor position.

In certain instances only limited borehole data may be available. In such cases it makes sense to be on the conservative side when selecting the size and weight of the proposed anchors. Anchor steel is relatively cheap compared to the day rate of installation vessels!

When a drag anchor is installed it is very difficult to determine the depth of the sea-bed penetration. This can make accurate determination of line pretension difficult if, during installation, the length of all the mooring line sections was carefully noted on the basis that this can be used to back calculate the pre-tensions.

Drag anchors normally have minimal corrosion protection, just a basic paint coating. Despite this corrosion has not been a problem even for anchors on drilling rigs, which have a much harder life than an anchor which sits deep into the sea-bed. Still given that field lives can be extended and that high quality coatings are available, it would seem logical to make greater us of such coatings.

Drag anchor fatigue life is typically far superior to that of the chain, which they are attached to. Hence, anchor fatigue life is normally only checked if specified by the anchor manufacturer’s client.

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7 CORROSION, FATIGUE AND WEAR (CASE

STUDIES)

7.1 The “Balmoral FPV” – An Industry Benchmark

The Balmoral Floating Production Vessel (FPV) represents an early North Sea semi-submersible production unit (see Figure 7-1). Unusually for the time, it was a purpose built production unit utilising a new GVA design and was built in Gothenberg in 1986. Hence, today (2005), it has been in continuous operation without dry docking for some 19 years.

It is also worth noting that the ‘Buchan’, ‘Amerada Hess 001’ semi-submersibles and the ‘Brent Spar’ have also seen long deployment periods. Some of the experience which has been gained from these units is discussed in Sections 8 and 11.

The Balmoral FPV was provided with a “Rolls Royce” mooring system consisting of driven anchor piles and 92mm R4 studded chain made in accordance with the new DNV standard to avoid brittle failures. The chain, when new, had a minimum break load (MBL) of 853t MBL. In addition, the FPV has 4 x 39 tonne maximum nominal thrust azimuthing thrusters, which are used in storm conditions to reduce mooring line tensions.

Figure 7-1 –The Balmoral Benchmark FPV which has been continuously on station since 1986 (Courtesy of CNR)

Despite some built in redundancy the FPV has experienced a number of line failures which are summarized in the plan view in Figure 7-2.

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Chart of the FPV Mooring System

6453500

6454000

6454500

6455000

6455500

6456000

6456500

563500 564000 564500 565000 565500 566000 566500

Easting

No

rth

ing

Kenter links

Touchdown

Missing or

loose studs

D-shackles

Pile 1

+2.7%

Pile 2

No measurements

Pile 3

-1.9%

Pile 4

+11.6%

Pile 5

+7.5%

Pile 6

No measurements

Pile 7

+33.5%

Pile 8

-25.7%

Figure 7-2 – Plan View of Mooring Incidents at Balmoral

Historically, Balmoral’s mooring lines were inspected and the studs pressed every 5 years on the back of an AHT. In 2001 one of the most heavily loaded windward lines was recovered and taken to Haugersund for detailed inspection by Chainco. Every other link was examined. Just one crack was discovered on the outer shoulder of a single link which was thought to be a random manufacturing problem

One section of the line had very loose studs and this was cut out and transferred to the chain locker on board the FPV. On this basis DNV accepted Welaptega Marine’s (see Section 18.4) in water ROV inspection for the other lines, rather than inspection of each line on the back of an anchor handler.

However, in November 2002 a leeward line broke. Despite a drop in the reported tension it took time to confirm that the line had definitely broken. This was because the break was in the mud and the line still had some catenary profile. Hence, one option was a partial line run out. The break was only confirmed when the line was pulled in on the chain windlass and a ROV saw the chain end emerge from the mud. This has definite implications for possible line failure detection methods – see Section 17.

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7.2 Corrosion and Wear Allowance – Discussion of Code Requirements

For long term integrity it is vital that wear and corrosion are correctly accounted for in the design process. This section reviews the existing guidance which is available in mooring design codes/recommended practices and then compares the specified values with what has been recorded in the field. It is worth noting that some earlier mooring systems were designed with no corrosion allowance. This ties in with what was specified in the design codes available at the time, e.g. POSMOOR code of July 1989 [Ref. 29]. Hence, if these early systems did not include much design margin (i.e. they just met their allowable loads) then wear and corrosion may fairly quickly cause a reduction in their capacities, such that they no longer meet their allowable loads. In some instances the safety factors in some of the earlier codes may have been higher, which thus by default effectively included some in built allowance for wear/corrosion. In a similar vein fatigue life calculation were not required by POSMOOR 1989.

In the absence of alternatives API RP 2I [Ref. 30] is sometimes applied to long term FPS moorings. API RP 2I has universal allowable reductions in chain diameter (see Section 7.5.3). These may not be appropriate for a long term FPS which does not have an inbuilt allowance for corrosion and wear. In such cases a new evaluation of the worn chain break strength should be undertaken. However, as is discussed in Section 7.3.3 an accurate assessment of the strength of worn chain is difficult to determine.

Draft ISO standard (19901-7) Part 7, Section 10.6 [Ref. 31] states for chain in the splash zone or in contact with a hard bottom sea-bed the diameter should be increased by 0.2mm to 0.8 mm per year of the design service life. The 0.8 mm per year is a significant increase compared to other codes.

API RP 2SK Section 3.1.2 states the following “Protection against chain corrosion and wear is normally provided by increasing chain diameter. The allowance in chain diameter for corrosion and wear is a complicated issue that still requires significant research and service experience to address. Currently industry practice is to increase the chain diameter by 0.2mm to 0.4mm per service year in the splash zone where oxygenated water tends to accelerate corrosion and in the dip or thrust zone on hard bottom where heavy corrosion takes place.”

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OS-E301, Table F1 Corrosion & Wear Allowance for Chain

Corrosion allowance referred to the chain diameter

Part of Mooring Line

No Inspection

(mm/year)

Regular inspection 1) (mm/year)

Requirements for the Norwegian

continental shelf (mm/year)

Splash zone3) 0.4 0.2 0.82)

Catenary4) 0.3 0.2 0.3

Bottom5) 0.4 0.3 0.4

1) Regular inspection e.g. in accordance with the Classification Societies or according to operators own inspection programme approved by national Authorities if necessary. The mooring lines have to be replaced when the diameter of the chain with the breaking strength used in the design of the mooring system is reduced by 2%.

2) The increased corrosion allowance in the splash zone is required by NORSOK M-001 and is required for compliance with NPD regulations.

3) Splash zone is defined as 5m above the still water level and 4m below the still water level.

4) Suspended length of the mooring line below the splash zone and always above the touch down point.

The corrosion allowance in the Table is given as guidance; lower values may be accepted provided it is documented.

Table 7-1 - Example of Specified Corrosion and Wear Allowances from One Classification Society

Section 59.2.2 (Concentrated Corrosion) of BS6349-1 2000 [Ref. 28] defines accelerated or localized corrosion as “concentrated corrosion.” Relevant factors include:

1) Repeated removal of the protective corrosion product layer.

2) Bi-metallic corrosion, where steel is electrically connected to metals having nobler potentials or where weld metals are significantly less noble than the parent metal.

3) Accelerated corrosion associated with microbiological activity.

In such circumstances typical corrosion rates of 0.5mm/side/year and as high as 0.8mm/side/year have been observed in the relatively cold UK coastal waters.

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7.2.1 Wear/Corrosion Rates Experienced in the North Sea

Figure 7-3 Illustration of the Extent of General Corrosion on a Recovered Floating Production Unit Mooring Line after 16 years service

The data considered in this section is based on a North Sea semi submersible based floating production facility that has been continuously operating for almost 20 years. On this unit a line failed in the thrash zone and a number of links close to the break were recovered back to shore. Dimensional checks of the most worn areas of this chain revealed 10mm of apparent wear/corrosion over 16.25 years based on the nominal chain diameter. This gives a wear rate of 0.615 mm/year in the thrash zone. As can be seen this is 50% higher than the value specified in OS E301 [Ref. 5]. If a higher wear rate is experienced than has been allowed for it is possible that after a set number of years the mooring system will no longer be capable of with standing the maximum anticipated storm loading. Since all the lines will be subject to wear, although not necessarily at the same rate, this could mean that if one line fails the remaining lines may no longer be strong enough to withstand the one line failed design case. In such a case there is a real danger of the mooring system starting to “un zip” itself and the unit loosing its station keeping capability.

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Figure 7-4 Illustration of the Extent of Corrosion Pitting

Figure 7-3 is a picture of some of the links which were recovered following the line failure. As can be seen the chain has experienced fairly heavy corrosion. In addition, Figure 7-4 shows the extent of corrosion pitting. The materials testing laboratory which examined the chain reported the following:

“The metal loss observed on all the links took the form of large areas of pitting where the metal loss was at least 2-3mm, with isolated areas of deeper pits with more severe metal loss. The entire outer bend region of some links was affected in this way, as well as large areas of the straight sections.”

A somewhat unexpected result from the examination of the links recovered from the thrash zone was damage to the crown of the links – see Figure 7-5. It is believed that, as tension is cyclically reduced, some type of impact or grinding action on the on inner edge of an adjacent link seems to be occurring (see Figure 7-6). It is also worth noting that the chain had very loose studs, hence it is possible that contact between the crown and the stud is occurring. However, there was no particular evidence on the stud itself of such a contact happening.

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Figure 7-5 – Example of the Damage Caused to the Crown of the Links

Figure 7-6 – Arrow shows the Apparent Grinding Action on the Inner Face of One of the Links

Another example of how the dynamic action of a moving link may cause damage to an adjacent item is shown in Figure 7-7. This photograph shows the beginning of a failure of a small hanging shackle which attaches an excursion limiting weighted chain section to the main links of a FPSO mooring line. The failure of the hanging shackle pin is likely to have been caused by the dynamic pinching action of the adjacent link plus the general rotation of the hanging shackle pin – see also Section 10.3.

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Figure 7-7 – Example of the Damage Caused to a Hanging Shackle Pin on a FPSO Mooring Line

When a chain is subjected to an applied load it is subject to a complex combination of tension, bending and shear loads. A finite element derived indicative stress pattern for a loaded link is shown in Figure 7-8. In this plot the highest stresses areas are coloured red. Comparing Figure 7-8 with Figure 7-6 shows that the area of apparent grinding damage approximately corresponds with one of the areas of maximum stress (see also 3.3.3). Hence damage in this area could result in a relative rapid reduction in break test capability. Another related factor here is the effect of corrosion pitting which in certain cases can be in excess of 3mm (see earlier).

Figure 7-8 Finite Element Stress Contour Plot (compare red areas with Figure 7-6) [Ref. 8]

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In Figure 7-8 it should be noted that the stress contours show a “weak” asymmetry about the X-Y plane due to simply supported constraints applied to the static end of the chain model and a static load applied to the dynamic end.

7.2.2 Wear in the Thrash Zone

The data in Figure 7-9 is based on a detailed measurement programme on a line which was bought back to shore after many years of use on a North Sea semi-sub FPS. Although there is quite a lot of scatter, the black poly line on the graph indicates maximum wear at the touchdown point indicated by the red dashed vertical line.

Chain Thickness vs Link Number

80

82

84

86

88

90

92

94

450 650 850 1050 1250 1450 1650

Link Number (for line 7 section)

Ch

ain

Th

ick

ness

(S

pecia

l M

easu

rem

en

t/2

) (m

m)

Line 7 Chain Thickness API Minimum Line 4 Thickness Poly. (Line 7 Chain Thickness)

BREAK POINT TOUCH DOWN @ 128Te

FPV PILE

835m 761m 687m909m946m983m1057m

Distance from Pile (m)

Figure 7-9 - Example of Thrash Zone Wear

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7.3 North Sea FPSO – Apparent Corrosion and Wear Data

This section is based on recent measurements on components which were recovered from a North Sea FPSO mooring system. Figure 7-10 and Figure 7-11 show the condition of a special shackle. The shackle was positioned approximately 40m out from the wildcat at the base of the turret at the transition from studless to studded chain. This shackle is much more pitted than expected considering that it was in the water for less than 7 years. It appears that some degree of galvanic type or perhaps sulphate reducing bacteria (SRB) induced corrosion has taken place. Galvanic type corrosion is perhaps more likely given the localised deterioration of the shackle pin (see Figure 7-11) where it has been in contact with studded chain.

On the studded chain heavy pitting of 2 to 3mm depth was noted where the chain connected to the shackle. This localised effect again supports the hypothesis of galvanic type corrosion between the shackle and the chain, which has affected some 26 links before the effect is dissipated. Pits can act as stress raisers – see Section 7.5.

Given that there is a length of studded chain without pitting between where the pitting has been observed and the fairlead, there is some evidence that this pitting is not due to any cathodic action from the FPSO itself. Since this phenomenon has developed either side of the shackle, it is logical to assume that the material characteristics of the shackle may be a contributing factor.

Figure 7-10 - Illustration of the Extent of Pitting Corrosion

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Figure 7-11 - Example of Wear and Pitting Corrosion on the Shackle Pin

The as forged dimensions on this shackle are not known with certainty, but typical dimensions are known. The pin of the shackle goes through the end of a common link of studded chain and the bow of the shackle goes through the studless chain. Based on nominal or typical dimensions significant wear appears to have occurred at the bow of the shackle with the bar diameter down from 170mm to 158mm (12mm) a major reduction in less than 7 years.

7.3.1 Chain Wear/Corrosion Assessment (Studded and Studless)

Since chains and shackles are typically forged the final dimensions after manufacturing are not known with any certainty, unless as built data is measured, recorded and the item can be identified. If this is not done the final as manufactured bar diameter at the inter-grip area may well not be known. As chain is manufactured it is bent around an anvil when red hot and this tends to reduce the bar diameter particularly where it is bent.

Based on the nominal chain diameter of the studless 142mm chain this shows an apparent maximum in field combined wear/corrosion of (142 – 134.5) 7.5mm over less than 7 years which at 1.07mm/year is high. So far the apparent wear and pitting corrosion seen on this chain has been 3.6 times (1.07/0.3) higher than was allowed for during the design process.

Based on the nominal diameter of the studded 137mm chain this gives a maximum combined wear/corrosion of (137 – 132) 5mm over less than 7 years which at 0.71mm/yr is also in excess of what was allowed for in the design process.

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In this case it would be useful to compare the relative shackle surface hardness with the existing chain to see if this or galvanic type corrosion is the cause of the high apparent wear/corrosion rate.

7.3.2 Discussion of the Consequences of the Apparent Wear/Corrosion Rate

It is appreciated that the quoted apparent North Sea wear/corrosion rate may well not be applicable to all geographical areas and unit types. However, if the rate is even roughly correct this may well have potentially serious consequences for units intended for long-term field lives. Thus it is important that this area is investigated further as a matter of priority - see Section 21.1.

7.3.3 Break Testing of all Chains

At the end of perhaps a 20 year deployment period the minimum break load of all mooring components on a FPS should still be able to meet the calculated maximum design load multiplied a suitable safety factor. However, we do not know how grinding, wear or pitting corrosion will affect the chain’s break load. An approximate estimate of the break test load could be obtained by using a finite element model representation. With such a model it would be difficult to have confidence that the finite element model is representative, particularly when hairline cracks may be present. Hence, it is recommended that as used mooring lines and components become available, either due to line failure or the completion of a FPS assignment, that representative lines should be break tested to see what their actual break load is after “X” years service. Figure 7-12 illustrates a test rig set up from a mooring chain break test.

Break testing such lines may also reveal the presence or otherwise of any fatigue cracks. Such cracks may not always be detectable using conventional inspection techniques. For example, Magnetic Particle Inspection (MPI) on recovered semi-submersible chain has found crack like indications at the inner bend region of all links. The materials testing laboratory doing the inspection judged these to be “Laps”. This feature occurs as the result of two mating links rubbing together, which causes a fold on the material surface. Due to the rough nature of the surface in this area it is not generally possible to do ultrasonic testing to assess the depth of these cracks like indentations. Hence, the desirability to obtain confirmation of the presence or otherwise of any obscured fatigue cracks.

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Figure 7-12 -Test Rig Set Up for Break Testing of Mooring Components (Studless Chain in the instance)

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7.4 Sulphate Reducing Bacteria (SRB) Induced Pitting Corrosion

Sulphate reducing bacteria (SRB) have been known to cause pitting corrosion in areas such as ballast tanks – see Figure 7-13. Unconfirmed rumours have indicated that SRB may have also caused rapid corrosion damage to mooring systems in the North Sea, south-east Asia and off Brazil. In certain areas, such as the Black Sea, it is believed that the concentration of SRB is higher and this is believed to have caused some difficulties for drilling contractors.

Figure 7-13 – Illustration of Biologically Induced Pitting Corrosion in a Ballast Tank

It is understood that biologically induced pitting corrosion tends to be more prevalent in warm oceans. Deep isolated pitting is a text book classic example of SRB attack. Thus microbial induced corrosion has potential implications for floating production units in the tropical oceans. SRB are anaerobic and can develop in a < 1mm thick layer of slime. These bacteria can cause severe corrosion by accelerating the reduction of sulphate compounds to corrosive hydrogen sulphide. Concern has also been expressed about the use of high strength mooring line steel in high H2S environments as it may lead to hydrogen embrittlement. This can also be affected by the amount of cathodic protection being applied (see also Par Ohlsson paper, 3rd Int. Offshore Mooring Seminar [Ref. 5]).

Standard bacteria cultivation tests exist to check for the presence of SRB. It is believed that it would be possible to collect a slime sample from a mooring line by means of a ROV or if necessary by diver. If a likely candidate FPS can be identified it would be interesting to undertake such a test to assess the concentration of such bacteria. In general 1 SRB per litre of sea water is fairly normal. Higher concentrations can be found in the sea bed top soil.

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7.5 Stress Corrosion Fatigue

Investigations undertaken by Vicinay Cadenas, Labein R&D, Bilbao University and others have shown that corrosion clearly affects the fatigue behaviour of steel mooring components.

Hostile environments, such as seawater, can accelerate the initiation and growth of fatigue cracks, particularly in the presence of mean tensile stresses. One mechanism is the development of corrosion pits, which then act as stress raisers. In other cases the environment causes cracks to grow faster by chemical reactions and dissolution of material at the crack tip.

To make fatigue life estimates (see also Section 16 “Fracture Mechanics and Critical Crack Size”) it is possible to apply the fracture mechanics characterization as represented by the Paris equation as shown below in terms of a curve of da/dN versus

K:

mKC

dN

da

In this expression “a” is the crack length, N is the number of cycles, K is the range of stress intensity factor. ‘C’ and ‘m’ are material and environment dependent constants which are typically determined in the laboratory. For chain, Vicinay has measured values for the exponent ‘m’ in different environments. The figures for dry air are lower (around m = 2.7), compared with the values of free corrosion in seawater that are m =

2.88. Below a threshold value of K cracks do not grow at all. Above a high level of

K crack growth is much more rapid as is illustrated in Figure 7-14.

Figure 7-14 - Crack Growth per Cycle versus Stress Intensity Range [Ref. 2]

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Vicinay, in conjunction with fracture mechanics, metallographic and materials science experts has further investigations in process to study the environment-assisted cracking (EAC) and particularly the hydrogen-assisted cracking (HAC) behaviour of chain.

7.5.1 Latest Work on Chain Corrosion

For certain oil and gas projects the required design life for production facilities may reach 30 years. An example of such a project is the Belanak offshore liquefied petroleum gas (LPG) FPSO facility offshore Indonesia. This hull has been designed and built to last 30 years without the need for dry docking and all mechanical equipment has been specified to last for this period. Such a long design life presents real challenges for a system which is exposed to continuous wear and corrosion, yet at the end of the field life must still be able to withstand a 100 year return period storm.

The recent OMAE Speciality Symposium on FPSO Integrity in Houston August 30 - September 2, 2004 included a paper looking at “Mooring Chain Corrosion Design Considerations for an FPSO in Tropical Water” [Ref. 33]. This paper reviewed US Naval Research Laboratory (NRL) data on corrosion rates from its 16 year test programme in a tropical area and from corrosion data for other geographical areas from other sources. In summary the US NRL’s test results indicate that a corrosion allowance of 0.2mm per year on one side should be sufficient for compensating the actual corrosion damage. This gives 2 x 0.2 = 0.4mm/year on diameter which ties in quite well with the existing codes. However, this is lower than the North Sea reference number reported in Section 7.2.1, i.e. 0.6mm/year.

What is perhaps significant here is that the 0.4mm/year rate discussed in the OMAE paper seems to only correspond to corrosion, the effect of wear seems to have been neglected. North Sea experience seems to indicate that wear can be quite considerable. In locations such as West Africa, where less extreme but regular FPSO motion can be expected year after year, the effect of wear is expected to be significant. Hence it is felt that a 0.4 mm/year rate to cover corrosion and wear is not conservative, at least for the North Sea. But still more data is needed from other types of units, which have seen long-term deployments in different geographical locations.

The design of the surface floating facility, the type of mooring and metocean conditions will affect wear rate. For example in 1982 4.5 inch diameter U4 grade chain on a CALM buoy failed due to excessive wear after two months, see Figure 7-15 [Ref. 34]. In this case the buoy anchor pattern was asymmetric with distinct strong and weak roll stiffness axes and surge stiffness axes. However, this incident shows that accelerated wear can be a real issue.

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Figure 7-15 – Illustration of Excessive Chain Wear on a CALM Buoy [Ref. 34]

7.5.2 Temperature, Salinity and Dissolved Oxygen Content

The following factors will influence corrosion rate all of which will vry to some degree depending on geographical location. :

Dissolved oxygen

Temperature

Salinity

Velocity of water particles

All other factors being equal corrosion rates are approximately proportional to the level of dissolved oxygen in the water. Oxygen content is influenced mainly by water particle velocity and temperature. As can be seen in Figure 7-16, (also see Figure 7-17) temperature drops with increasing water depth and hence oxygen content increases. Thus this is a potentially undesirable effect from a corrosion perspective for deepwater FPS’s.

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Figure 7-16 – Typical Temperature and Salinity Profile in the Tropical Oceans

Figure 7-17 – Indicative Oxygen Concentration versus Water Depth (courtesy of BP)

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Figure 7-18 – Gulf of Mexico Snap Shot of Bottom Oxygen Concentration

(courtesy of BP)

Salinity in terms of the chloride content of sea-water increases corrosion rate by increasing electrical conductivity and adversely affecting development of the protective films on the chain surface. It can be seen from Figure 7-16 that there is an approximate change in salinity of approximately 7.7% from the surface down to a depth of about 3,000m.

It can be seen from the values reported in this section that the corrosion behaviour of deep water mooring systems is presently uncertain.

7.5.3 Inconsistency in API RP 2SK and RP 2I

Wang and D’Souza’s OMAE paper identified an inconsistency between the mooring chain inspection requirements defined in API RP 2I (“In-service Inspection of Mooring Hardware for Floating Drilling Units,” and RP 2SK (“Recommended Practice for the Design and Analysis and Stationkeeping Systems for Floating Structures.”) Although RP 2I is not necessarily appropriate for a FPSO it would be logical to apply it to a semi submersible production unit.

Section 3.4 of RP 2I states “Links having any of the following problems should be removed: an average diameter of two measured diameters less than 95% of the nominal diameter (about 10% reduction of cross sectional area) or a diameter in any direction less than 90% of the nominal diameter. This is a different approach to the corrosion rate specified in RP 2SK.

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An example helps to illustrate the difference between the two approaches. Take a chain designed to have a net diameter of 105mm for a 30 year service life. Applying a 0.4mm per year corrosion allowance results in a final diameter of (30 x 0.4) + 105 = 117mm. After 25 years assuming the 0.4mm per year corrosion allowance the chain will still have a sound diameter of 117 – (25 x 0.4) 107mm which would still meet the original design requirement. However, this remaining diameter of 107 fails the RP 2I inspection criteria of 0.95 x 117 111mm.

Obviously it is undesirable to have an inconsistency between two API reports. It is believed that API 2I is due to be revised and it would be desirable for this inconsistency to be resolved at this time.

7.6 Wear Analysis (Shoup and Mueller Work)

As was mentioned in Section 7.5 an interesting example of how wear can lead to mooring line failure is provided by the failure of a CALM buoy just two months after installation. This was investigated by Shoup and Mueller in their OTC paper 4764 from 1984. Although this is a now a fairly old paper, it is still a particularly useful work in the respect of surface hardness and wear prediction.

Wear is a complex process involving material properties, forces, sliding distances and environmental factors, such as sea-water immersion. Hence, rather than relying solely on theoretical analysis, Shoup and Mueller undertook an experimental wear study. Because of the cost of full scale component testing, it was decided to perform wear tests on smaller size specimens simulating as closely as practical the actual service conditions. Figure 7-19 shows the wear results obtained from the crossed cylinder wear tests. Both U3 and U4 marine/ship grade chain had high initial wear rates, followed by a distinct knee and a nearly linear lower rate after approximately 150 cycles. The knee and the plateau were probably caused by the decreased contact pressure and reduced sliding distance resulting from wear. The presence of sea water which provided lubrication caused a distinct reduction in wear. This has implications for external turret moored FPSOs in benign climates.

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Figure 7-19 - Measured Wear Rates of U3 and U4 Chain at 8,170lbs (300 tonnes equivalent) [Ref. 34]

These experimental tests identified wear rate coefficients which are dependent on applied tension and whether the chains were in air or sea-water.

Using this data a modified form of Archard’s wear equation was developed of the following form:

where:

F = chain tension

Ø = roll angle (degrees)

r = radius of the chain barstock

K = wear coefficient (dependent of F)

N = number of records

TWV = total wear volume for the duration of the test

3........180

12

11

1

iriiFiFi

TMVN

i

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7.6.1 Shoup and Mueller’s Key Conclusions

The conclusions from Shoup and Mueller’s paper are interesting and have potential implications for the reliability of the mooring systems on deep water floating production facilities. Hence, they are reproduced in full below:

“The most important result of the study is the realization that wear is an important criteria for anchor leg design, especially for deepwater systems. Deepwater catenary systems are prone to anchor chain wear because:

1. Overall system elasticity and surge motion increases with water depth. As surge motion increases, interlink motions also increase.

2. Catenary chain moorings have large pretension interlink forces in deep water. The wear study shows wear rate increases dramatically with increasing load (particularly at the floating structure interface).

Catastrophic wear failure of catenary anchor leg lines (at the floating structure interface) can be prevented by:

1. Placing large links below the chainstoppers to keep the gross contact pressure below the high wear rate regime.

2. Using a stopper casting support which is free to rotate about two perpendicular axis. This will eliminate most of the wear generating interlink motions.

3. Studying the behaviour of links in the wear zone to determine if a particular mooring arrangement generates large relative sliding distance between links.

With respect to point 2 it is worth noting that that most FPSOs only allow stopper rotation about one axis rather than two (see Figure 9-3). For spread moored FPSOs it will be interesting to see if wear experienced in the field may make adopting a twin axis approach worthwhile.

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7.6.2 Calibration of Up to Date Wear Analysis Model with Offshore Recorded Values

With modern dynamic analysis mooring packages, it is possible to predict the relative rotation between individual links for different line tensions/sea states. There are now a number of FPSs which have been operational for a number of years and from which indicative wear rates are available. Hence, there is benchmark data which can be potentially used to validate a wear analysis assessment and assist with the selection of wear rate coefficients. Thus, it is recommended that such an exercise should be undertaken (see Section 21). Once a good validation has been achieved it should be possible to apply the developed methodology to a planned new deep water long-term FPS. It should be possible to take into account the system specified pretension and expected environmental conditions and vessel response. In this way the calculated wear rate can be compared with the code specified wear and corrosion rates (see Section 0). If the calculated value is higher than the code specified value a cost benefit analysis may be required to assess whether increasing the line diameter is more cost effective than carrying out a replacement operation some time during the field life.

7.6.3 Enhanced Wear and the Possible Development of Loose Studs in the Chain

Lockers

On all the lines in the chain locker on the FPSO with adjustable lines discussed in section 9.1, there will be two slack sections where the chain hangs off from the bitter end shackle and down from the ceiling mounted gypsy wheel. As the FPSO responds to the environment these slack chain sections will move around and may be subject to wear within the locker, which might not normally be expected for un-tensioned chain in the chain locker. The motion of the chain added to the possibility of corrosion inside the chain locker could lead to the development of loose studs. On this unit loose studs were found in a 17 link, chain section, which was pulled out from the chain locker.

Previous experience with chain storage in lockers on semi-subs indicates a potential for corrosion pitting damage. To quote, “chain which normally remained in the locker exhibited severe localized corrosion in the form of deep pitting. This was unexpected. However, the severe pitting probably resulted from the formation of oxygen concentration cells at points of contact within the stored pile of chain. The moist salty environment provided electrolyte and the varying local concentrations of oxygen provided the anode/cathode galvanic potential” [Ref. 35].

Pitting corrosion and the wear are both potentially significant points, since you do not want to adjust line lengths to reduce wear and possibly by doing so introduce weak links into the system, which were not previously under high tension – see Section 9.1.

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8 UNBALANCED LINE PRE-TENSIONS (CASE

STUDIES)

8.1 North Sea Semi-Submersible FPS

When a mooring analysis is undertaken the pre- or working tensions are set at specific values, which are often identical. This is a reasonable approach as long as the unit in the field can set their line tensions to comparable values. If the set up line pre-tensions on a FPS are unbalanced, this can lead to increased maximum line tensions and reduced fatigue lives. In addition, in case of a single line failure this can lead to an increased transient excursion, which might exceed the allowable watch circle.

On a North Sea semi-sub FPS the offshore personnel doubted the tension readouts were accurate because:

Sometimes the wire became partially bedded into, and/or damaged the lower wrap on the winch drums

When grappling for certain components on the mooring line they were not found at the expected depth.

Therefore, an underwater ROV survey was taken of the flounder or tri-plate connectors on the mooring lines to obtain their x, y and z co-ordinates. From these positions and knowing the submerged weight of the line it was possible to undertake a catenary line calculation to determine the actual line tension. These tensions can then be compared to the tension readouts on the rig at the time that the ROV position check was made. It was found from this process that the calculated tensions and the measured tensions could be out by up to 160% in the worst instance!

There are a number of potential reasons why the tension meters were so far out. These include:

The meters have not been calibrated or the calibration has drifted over time

The gypsy wheels may be seized

The instrumentation is not sufficiently sensitive

The tensions are measured at the base of the winches in board of the fairleads

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8.2 Line Payout/Pull-In Test

To confirm whether or not the gypsy wheels were seized and to assess the sensitivity of the tension meters, a carefully controlled Line Payout/Pull-In Test was undertaken. In this test each line was paid out in 2m increments and the line tensions were recorded. The lines were then pulled in by the same amount and the line tensions recorded. If this test is undertaken relatively quickly in good weather, it would be expected that the same tension would be obtained for the same line payouts. However, this was revealed not to be the case in all instances, see for example the plot below for Line Number 11.

Line No11

185.0

186.0

187.0

188.0

189.0

190.0

191.0

192.0

193.0

194.0

195.0

0.0 20.0 40.0 60.0 80.0 100.0 120.0

Tension (te)

Wir

e p

ay

ou

t (m

)

Figure 8-1 – Illustration of Line Tension Variations during a Payout/Pull-In Test

The “wiggles” on this graph are believed to be due to due to the sheaves binding and then becoming free and then binding again. It is understood that a similar “wiggle” pattern has been recorded during a Payout/Pull-In test on a Gulf of Mexico Spar.

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8.3 North Sea FPSO

This FPSO is fortunate, compared to FPSOs where the mooring lines are stoppered off at the turret base, in that loadcells are available which can provide a rapid means of verifying mooring line tensions. In principle loadcells should be able to detect both extreme event line tensions and normal working tensions. However, on this particular unit not all the loadcells are working properly and the offshore personnel have little confidence in the reported values. In addition, the wildcats could be partially seized, which would influence the line tension readings.

Obviously if loadcells are uncalibrated the results cannot be treated with confidence. But also on a single loadcell unit, with a very large reporting range, the sensitivity to accurately establish the lower pretension value is uncertain, as seems to be demonstrated by this FPSO. Hence consideration should be given to using two loadcells on each mooring line. The first would be accurate at the pre-tensioning load ( 100t) level. The second loadcell would have sufficient range to monitor loads during storm conditions ( 1,000t).

8.3.1 Chapter Conclusions and Recommendations

Historically semi submersible drilling units have been subject to relatively frequent mooring line failures which equate to approximately one failure per three operating years. Sometimes these failures cannot be attributed to obvious causes. The work reported in this section shows that it is possible for a carefully set up Rig to have a seriously unbalanced mooring pattern, which may well not be detected by the Operator. Such a Rig would thus be in greater danger of mooring line failure.

If the tension meters are well positioned, working properly and their calibration is in date, a likely cause of unbalanced line tensions is partial seizure of the gypsy wheels. This can be confirmed by a simple line Payout/Pull-In test. If this reveals that some of the gypsy wheels are partially seized an attempt should be made to free them up. However, if the unit is on station it may not be feasible to undertake such work in situ. In such a case the line tensions out with the fairlead should be determined by other measures such as:

ROV or possibly diver monitoring of the chain angles where they emerge from the fairleads

Acoustic monitoring of the x, y and z positions of specific connectors on the mooring lines

From these measurements it is possible to back calculate the actual line tensions as long as this is done in calm conditions with minimal tidal variations.

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At present it is not known how common a problem this could be for other operating units. Seized wheels may be more likely on a wire sheave than on a chain gypsywheel/wildcat. Hence, it is recommended that similar Payout/Pull-In tests are repeated for a number of different ages and designs of Semi-Submersibles. This is recommended in the HSE’s recent research report 219, “Design and Integrity Monitoring of Mobile Installation Moorings” [Ref. 36].

Azimuth Checks and Marine Growth

If a gypsy wheel is partially seized with respect to rotation it may also be seized relative to azimuth rotations. Hence, as well as checks gypsy wheel checks on free running, the ability of the fairlead assembly to freely slew or azimuth should also be confirmed. If the fairleads cannot azimuth freely increased chain wear is likely to occur. In practice the best way to achieve this in the field may be to examine the marine growth at the fairlead to see if it has been displaced as the gypsy wheels azimuth. If there is no evidence of removal of marine growth it is likely that the fairleads may be seized in the azimuth direction and may also have problems rotating!

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9 MOORING BEHAVIOUR AT THE VESSEL

INTERFACE (CASE STUDIES)

The design of the vessel interface needs to minimize the potential for wear, corrosion or other forms of degradation. However, in field experience is demonstrating that this is not always being achieved. This is discussed in this chapter. The key points are relevant to mooring systems in general, not just to one particular design or even type of floating platform. Although turrets are discussed in detail the key points are relevant to Spars, spread moored FPSOs and semi-subs.

9.1 Permanently Stoppered Off Versus Adjustable Lines

There are a number of different turret designs available on the market. On many turret designs the chains are stoppered off at the base of the turret – see Figure 9-2. There are also a fewer number in which the line lengths can be adjusted during the life of the unit – see Figure 9-1. In addition, there is at least one unit which uses wire into the turret as opposed to chain. Although there are many different designs, including both internal and external turrets, it is possible to categorize them as follows:

a) Non adjustable permanently locked off chains at the turret base,

b) Adjustable chains which come up through the turret and are stored in a chain locker.

On Type a) systems the line tensions are not normally intended to be changed at any time throughout the field life. Type b) systems use a wildcat at the base of the turret similar to that found on a semi-submersible drilling unit running chains. Type b) FPSOs typically adjust their lines lengths and tensions either annually or even monthly. On some designs of spread-moored FPSOs the line lengths are also not intended to be adjusted and the required equipment for adjustment may not normally be present.

Being able to chain the line lengths has the following beneficial effects:

1) Distributes the high wear point on the chain over several links thus prolonging

chain life.

2) Distributes the wear over several gypsy wheel pockets, thus prolonging gypsy

wheel life.

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Figure 9-1 - Turret Design in which Chain Lengths can be Adjusted (courtesy of Chevron-Texaco)

Figure 9-2 – Generic Turret Design in which the Chains are Stoppered off at the Turret Base (courtesy of Bluewater)

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If the line lengths are never adjusted during the field life this means that the same links in the thrash zone and at the turret interface will need to withstand the majority of the degradation. In addition, inspecting lines in situ is more difficult, since the chain is relatively inaccessible inside the trumpet/chain stopper. It is also much more difficult with such designs to pick up the chain off the sea-bed to make it more accessible for in water inspection (see Section 18).

Being able to adjust line lengths can introduce its own perils, although these should be controllable. During a regular line tension adjustment operation on one North Sea FPSO there was a failure of the lifting and locking mechanism resulting in a complete line run out (see Section 0).

On type a) systems the trumpets are typically pivoted about a single axis so as to minimize chain rotation and wear. Since the rotation is only about one axis and the trumpets are arranged around an approximate circle, the pivoting action cannot eliminate chain rotation for all the lines at the same time. Thus, to minimize wear over a long field life, there may be arguments for selecting a design which can pivot about two axes, although this would be mechanically more complicated. This may be particularly relevant to spread moored FPSOs which cannot weather vane. Hence, there may be more wear at the chain/hull interface when the weather is not directly on the bow. Depending on location the weather coming in on the vessel’s quarters may occur for a significant proportion of the time.

Figure 9-3 - Spread Moored FPSO Single Axis Chain Stopper (courtesy of SBM)

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Trumpets or guides are normally included on type a) FPSO designs to help guide the chain into the chain stopper. The trumpets themselves may include “angle iron” guides to ensure that the chain is in the right orientation when it enters the chain stopper. Once the chains are tensioned the trumpets have no real purpose unless they are required in the future for a new chain pull in operation. Interestingly, the pivoting chain stopper design which was adopted for the Brent Spar buoy did not include trumpets to help guide in the chain see Section 11. However, in this case the chains in the stoppers were probably pre-rigged before the Spar was towed out to location. A kenter joining shackle was then used to connect up the chain in the field before the line was tensioned up. If you have a reliable method of connecting up in the field this approach does have some advantages. For example, the trumpets can be dispensed with and it is also easier to undertake a change out of the top chain section at some stage during the field life if required without cutting the chain. This illustrates the importance of having long-term reliable connectors, which is an area which still requires further work.

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9.2 Wear at Trumpet Welds – Internal and External Turrets

9.2.1 External Turret

On a number of type a) turret configurations wear has been experienced where the chains have been rubbing against the weld beads, where the bell mouth joins with the parallel trumpet section (see Figure 9-6). This was first experienced on an early S.E. Asian external turret moored FPSO. For this external turret, in air access was such that it was possible to shroud the chains where they were rubbing against the weld beads with a replaceable material (ultra high molecular weight polyethylene (UMPHE) sheeting). This whitish material can just be seen on Figure 9-4 poking out of the trumpets. In this case the weld beads were left as they were with no attempt to grind them down smooth. On this project UMPHE has been successful in stopping the chain wear, however, the sheeting needs regular inspection and replacement when it becomes worn or damaged. Hence, this is a solution which is only suitable where access is good, not for a submerged turret, in a harsh environment.

Figure 9-4 - External Cantilever Turret which experienced Chain wear at the Trumpet Welds which was halted by use of UMPHE (courtesy of Shell)

Considerable wear has also been noted on the chains which are normally in air on a benign climate external turret unit. Water lubrication may be a possibility to minimize the wear rate on such units – see section 7.6.

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9.2.2 Wear at Trumpets - Internal Turret

In the North Sea mooring lines are typically inspected utilising a work class ROV which performs a fly by of the lines. During one of these surveys a slight shadow was seen on one of the chains at the trumpet interface during the annual workclass ROV chain survey. Unfortunately, the large work class ROV was unable to get close in enough to inspect this shadow to determine whether it was simply removal of marine growth and mill scale, or if a notch was being ground into the chain (see Figure 9-5). To investigate this apparent anomaly further, a test tank mock up of the chain and trumpet assembly was built so that the capability of using a football sized micro-ROV (see Figure 17-5) to get in close to the bell mouth could be evaluated. This test tank test is illustrated in Figure 9-6. Micro-ROVs are particularly attractive for inspecting around the base of the turret since they can be deployed from the FPS itself rather than employing the services of a ROV support vessel. A micro-ROV can typically be deployed over the side of the FPSO either by hand or using a simple lowering frame. In addition, on some FPSOs there may be a spare “I” tube which is wide enough for the micro-ROV to be lowered down through. The test of the micro-ROV was successful ands it was subsequently deployed in the field. Figure 9-7 illustrates one of the photographs taken by the micro-ROV in the field. Marks can be clearly seen on both left hand and right hand faces of the chain where it has been in contact with the trumpet.

Figure 9-5 - Example of the Level of Inspection Detail which can be achieved using a Typical Workclass ROV (courtesy of I.Williams)

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Figure 9-6- Test Tank Mock-Up of Micro-ROV inspection of Chain Emerging from Turret “Trumpet” (courtesy of I. Williams)

Figure 9-7 - Micro-ROV Photograph of Chain Wear Notches where Chain Emerges at the Trumpet Bell Mouth (courtesy of I. Williams)

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Even with the better image resolution provided by the micro-ROV, quantifying the exact extent of the chain wear was difficult. However, it can be seen from

Figure 9-8 that it was potentially significant if the illustrated reduction in bar diameter is correct. In addition, it can be seen from Figure 9-10 that the location of the notch is in an area which is subject to significant reduction in bar diameter when a chain is loaded up to its MBL. Unfortunately, there is little data available on how reduction in bar diameter can affect chain strength. To try and determine as reliably as possible how a notch in the chain would affect strength, a notch was ground into some spare chain links left over from the original installation – see Figure 9-9. This link was then break tested to assess how much the chain MBL had been reduced by the presence of the notch.

6

1

6

1

Figure 9-8 - Indication of the Extent of the Wear

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Figure 9-9 - Artificially Introduced Notch on to Spare Chain Links, note also Red Circular Infrared Target (courtesy of I. Williams)

Figure 9-10 - Example of Stretched Chain during Break Testing, the Blue Mark Shows the Location of a Typical Notch (courtesy of I. Williams)

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The results from this break test of the notched chain indicated that it was likely that some of the as installed mooring lines would no longer meet the required mooring line safety factors. Even if the lines were still within the required safety factors, it would just be a matter of time until they became out of specification and when this might happen could not be reliably quantified. In addition, there was some possibility that fatigue cracks could have developed due to the regular knocking action which, if present, would reduce the break strength considerably. At present no technology exists which can check for fatigue cracks underwater, particularly in such an inaccessible area. Therefore, the decision was made to undertake a repair operation to change out the links going through the trumpets by custom built chain links of the same length as the existing chain, but made from a larger bar size. In addition, the new links were given a special hard cobalt chromium anti wear coating – see Figure 9-11. Further details of the repair operation can be found in Section 18.8.2.

Figure 9-11 - Example of a Special Cobalt Chromium Anti-Wear Coating (courtesy of I. Williams)

9.2.3 Actual Chain Condition after Recovery

It is interesting to compare the actual condition of the recovered compared to its expected condition. Figure 9-12 shows one of the recovered links. This figure clearly demonstrates that the wear was gradually eating into the side of the chain, thus progressively weakening the link. Although the extent of the wear was not as bad as some of the earlier predictions, it was clear that the wear would get worse over time. Fortunately, Magnetic Particle Inspection (MPI) of the key links did not reveal any hairline cracks, but this was not known beforehand. As well as the wear due to contact with the weld beads, additional damage was noted along the chain which was lying along the trumpet and sitting in the stopper – see Figure 9-13.

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Figure 9-12 - Photograph of a Recovered Link Showing a Wear Notch (courtesy of I. Williams)

Figure 9-13 - An Example of the Chain Damage noted after the Notched Chains had been recovered back to Shore (courtesy of I. Williams)

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9.2.4 Reasons for the Wear

It is significant to note that the chain stopper on type a) designs is typically inboard of the pivot point - see Figure 9-14. This means that the trumpet assembly does not automatically follow the motion of the chain. In fact it is contact between the chain and the outer face of the bell mouth which causes the trumpet to rotate – see Figure 9-21. It is this contact, plus an associated sliding/sawing action, which seems to have led to the chain notches.

Figure 9-14 - Turret Arrangement where the Chain Stopper (in red) is Behind the Rotation Point (2 black concentric circles)

Should the Stopper be behind or in front of the Pivot Point?

It is helpful to consider the pros and cons of having the pivot point behind the chain stopper (i.e. the rotation point is closest to the hull). Some spread moored units have gone the other way (see Figure 9-16). This approach seems to ensure that the compliance introduced by the bearing takes out as much of the motion as possible and the metal to metal contact as illustrated in Figure 9-15 is avoided. It will be interesting to see how much wear is experienced in the field by the designs with the stopper outboard of the pivot point. It will also be interesting to see what happens to the chain which is under low tension from the stopper up to the deck of the FPS – see Section 9.2.5.

Implications of Long Trumpets

For chain stoppers which are inboard of the pivot points it would appear that long trumpets are not helpful after the completion of the installation process. Thus it is recommended that careful checks should be made on any FPSOs which fit this category [Ref. 37].

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Figure 9-15 – Illustration of Potential Wear at Metal to Metal Contact (courtesy of I. Williams)

Figure 9-16 - Fairlead Chain Stopper where the Chain Stopper is in Front of the Rotation Point (used on some Spread Moored FPSOs) (courtesy of Maritime Pusnes)

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Figure 9-17 - As Installed Photo Graph of the Design Shown in Figure 9-16 (courtesy of Maritime Pusnes)

Compatible Surface Hardness

In general achieving compatible chain surface hardness is important for long term integrity, since it affects wear. Unfortunately, at present chain hardness and wear do not seem to be evaluated in any detail. These factors should be taken account of during detailed design, but more work is needed on this area before it becomes part of the standard design process.

Having the pivot point behind the chain stopper may date back to the original design of CALM buoys (see Figure 9-18). However, as far as can be determined the early “Shell buoys” did not have long trumpets and thus wear at the end of the trumpets may not have been an issue. Given that a tried and tested working design from CALM buoys was already available it is not surprising that this detail was incorporated into early FPSO turret designs which were not initially deployed in harsh environments.

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Figure 9-18 – Typical CALM Buoy Chain Stopper (courtesy of “The Professional Diver’s Handbook” [Ref. 38])

On the subject of CALMs Figure 9-19 shows an Imodco buoy with a rubber casting used to minimise wear at the lip of the trumpet. Thus, it is clear that potential wear in this area has been an issue for a number of years. Significantly during installation it is apparently difficult to get the rubber castings in exactly the right place.

Figure 9-19 - Amoco CALM Buoy- Note Inclusion of Rubber Casting (courtesy of[Ref. 38])

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9.2.5 Alternative Fairlead Designs

The traditional fairlead arrangement on a semi-sub is illustrated on the upper two sketches of Figure 9-20. With this design the chain where it runs round the lower wildcat is under high tension, particularly in storm conditions. With this type of design the first free link “hinges” on the last link in the fairlead pocket as the chain catenary angle changes. Thus the chain scrubs the surfaces of the pocket and whelp under high contact pressures. Hence, over time, both the chain and the wildcat will suffer from wear and damage – see Figure 18-8 and Figure 18-9. An alternative design is presented in the lower two sketches of Figure 9-20. In this design the in the motion between the chain and the surface platform is mainly taken out at a horizontal pin which attaches the stopper to the floating vessel and also by a freely azimuthing assembly.

With this alternative design it is important that the chain should not be actually slack from where it runs from the chain stopper to the windlass or chain jack. If the line is too slack there may well be excessive movement between links as the surface platform responds to wave excitation. Excessive movement can lead to accelerated wear. If wear happens above the stopper and then line is let out a weak point may be introduced in the system. However, not too much back tension should be included since it is important that the whole chain stopper assembly should still be able to azimuth freely.

It is important that the in field performance of these new designs of fairleads should be studied after a few years of operational experience to check whether they are performing as well in situ as hoped. This information then needs to be fed back to the wider mooring community.

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Figure 9-20 - Comparison of Alternative Fairlead Arrangements (courtesy of Bardex)

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9.3 Use of Bending Shoes

Before concluding this section on mooring lines at the vessel interface it is appropriate to also include mention of bending shoes. As can be seen from Figure 9-21 and Figure 9-22 bending shoes can be used both for wire rope and chain. At present there is little data available in the public domain comparing the performance of bending shoes to either wildcats/gypsy wheels or permanently stoppered off designs. It would be extremely helpful to track down such data, since it could be that a well designed bending shoe could help to preserve the life of the mooring line at the vital vessel interface.

Figure 9-21 – Example of a Wire Rope Bending Shoe (courtesy of API RP25K)

Figure 9-22 - Example of a Chain Bending Shoe Design [Ref. 39]

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For wire rope cyclic stresses from bending will shorten its service life because of fatigue. Fatigue resistance (service life) increases as a ratio of bend shoe diameter to wire diameter (D/d) increases. Individual wires move relative to one another and to the bearing surface as the rope bends causing abrasion. Abrasive wear increases as D/d decreases. Under heavy loads, the rope flattens against the bearing surface, increasing relative motion between strands and wires. Lubrication and large D/d ratios mitigate the adverse affects of bending. Minimum D/d ratios are available for different rope constructions [Ref. 19 – 7-2.12].

Chain works most efficiently when loaded in pure tension. Tensioning chain that is bent over a surface introduces bending stress that reduces load carrying capability. It is thus recommended that Chain should not be tensioned over surfaces with diameters less than seven times the chain diameter. Thus sharp bends and corners should be avoided [Ref. 19 7-29].

The bending shoe design illustrated in Figure 9-23 includes an angle sensor which can be used to back calculate the static line tension. However, given the problems outlined in Section 0 it will be interesting to see if the dynamic behaviour of the chain at this point over time may cause wear problems. The particular application illustrated is in deep water and hence line dynamics (whipping/fluid drag) will affect tension. In other words the recorded angle may not give an accurate idea of the tension in the line.

Figure 9-23 - Bending Shoe Design which includes an Angle Sensor [Ref. 40]

Another point to note on this project is that the chain is locked off and it is not planned to be moved regularly. In fact the chain jacks were removed after installation and will be re-installed as required during chain inspection. Not being able to work the chain will affect its fatigue life, so it will be interesting to see how well this mooring system performs over time.

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10 FURTHER MOORING CASE STUDIES

10.1 Wire Rope Systems

A number of floating production/storage units’ ropes within their mooring systems have seen periods of extended operation in the north sea including :

- AH001 - Buchan FPS - Emerald Producer FPSO

A number of wires from these units were removed and examined as part of two previous JIPs [Ref. 41 and Ref. 42]. The inspection of these lines confirmed that wire will be subject to degradation at the fairlead region and in the thrash zone. Hence, if IWRC wire is used in these locations it will typically need to be replaced after about 8 years service – see Table 3-9. Further information on when to discard IWRC mooring lines can be found in Chaplin 1992. Figure 10-1 from Chaplin 1992 [Ref. 43] gives an idea of the type of degradation which IWRC rope can be subject to :

Figure 10-1 – Examples of the Subjectivity Associated with Assessing IWRC Rope Conditions [Ref. 43]

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10.2 Unintended Line Disconnection

On a North Sea dis-connectable FSU (see Figure 10-2) the mooring wire and socket was found to have parted from the triplate assembly. An in-water survey showed the line to be in normal alignment, but separated by 36m from the triplate assembly, which was still securely attached by the mooring chain to the suction anchor. Inspection of the mooring line socket showed the socket retaining pin to be displaced, as one of the circular retaining plates which keep the pin in place had parted from the socket body (see Figure 10-3). It should be noted that the initial design prevented pin from rotating, also Section 14.1.2.

Figure 10-2 - Illustration of the Mooring Layout and Connections

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Figure 10-3 - Photograph of Disconnected Socket on the Sea-Bed (courtesy of BP/Stolt Offshore)

Figure 10-4 - Note End Plate also seems to be Falling Off on the Right Hand Side (courtesy of BP/Stolt Offshore)

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Figure 10-5 - End Connection Detail

Figure 10-6 - Illustration of Socket Minus End Plate

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10.2.1 Probable Causes of the Failure

There was a relatively steep change in mass per unit length at the triplate. This meant that the line at the forged tri-plate was subject to:

repeated pick up and set down contacts with the seabed, and

quite large relative rotations between chains, the wire and the tri-plate elements.

This resulted in rotational torque being transmitted from the wire socket through the retaining pin into the tri-plate and finally out to the chain cable via the LTM shackle. The pin retaining plate is bolted both to the pin and to the socket body the pin. The pin cannot rotate and the torque must be resisted by these bolts. These bolts either became loose and fell out, or failed in shear/fatigue.

How was it Rectified?

The problem was rectified by using more and bigger bolts on the end plate and allowing it to rotate – see Figure 10-7. The issue of whether or not to allow the pin to rotate is discussed in greater detail in Section 14.1.2.

Figure 10-7 - Repair Utilised Bigger Bolts and Allowed the Socket Pin to Rotate

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10.2.2 Anode Failures

Excessive corrosion was noted on the moorings wires discussed in Section 10.2. Therefore a series of anodes were retrofitted on the lines to control the corrosion level – see Figure 10-8. The anodes were inspected after approximately 12 months service – see Figure 10-9, where it can be seen that a number had become disconnected. There are a number of possible reasons for the anodes becoming disconnected and, due to commercial reasons it is not possible to discuss these in detail. However, from a mooring integrity point of view the key message seems to be “keep your catenaries clean” – see also Section 10.3. In other words avoid adding anything on to the catenary, particularly in the thrash zone.

Figure 10-8 - Example of Retrofitted Anodes to Control Corrosion Rate

Figure 10-9 - Example of Disconnected Anodes after approximately 12 months of Service

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10.3 Excursion Limiting Weighted Chain Problems

Excursion limiting weighted chain designs (see also Section 3.1.6) have been adopted for certain FPSO projects. However, as can be seen from the two projects discussed in this section, their use can cause problems. Figure 10-10 and Figure 10-11 illustrate clump weights used on a North Sea FPSO. Unfortunately, as can be seen from Figure 10-10 a number of clump weights have come off in service. It is not feasible to re-attach the clumps without recovering the lines to the surface, which is a major costly exercise.

Figure 10-10 - Example of Detached Clump Weight on the Sea-Bed

Figure 10-11 - Example of Recovered Clump Weights

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Figure 10-12 illustrates an alternative weighted chain design utilising hung off chain tails. However, this design has also seen problems as is discussed in Section 7.2.1 and illustrated in Figure 7-7.

General Location of

Damaged Shackles

General Location of Excessive Wear

General Location of

Damaged Shackles

General Location of Excessive Wear

Figure 10-12 – Illustration of Where the Damage Occurred on the Mooring Catenary

10.3.1 Use of Parallel chains to Increase Weight

Figure 10-10 illustrates an excursion limiting weighted chain design which has operated successfully in the North Sea since the later half of the 1980’s. As can be seen it utilises a parallel chain design.

Figure 10-13 - Example of a Parallel Chain Excursion Limiter (courtesy of I. Williams)

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If adopting such a solution with more than 2 parallel chains it is necessary to appreciate that the chains will not be of identical length and thus will experience different tension ranges. Hence the chains need to be suitably sized. In addition, it is important to still inspect the chains regularly. Figure 10-15 shows the extent of wear that can still occur due to the dynamic motion in the thrash zone. Thus whatever connectors are selected need to be robust.

Figure 10-14 - Weighted Chain Option Utilising Parallel Chain Sections (courtesy of N.Groves)

Figure 10-15 - Red Arrow Illustrates the Local Wear can take place when utilising Parallel Chain (courtesy of N. Groves)

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10.3.2 Buoys on Mooring Lines

Problems with submerged mooring line buoys have been encountered on a European based FPSO (see Figure 10-16). Figure 10-16 and a semi-submersible production unit. It is interesting to note that in Figure 10-16 the failures have occurred on leeside or breasting lines, not windward lines.

Line 10,

shackle

buoy

failed,

2001

Line 1,

shackle

buoy

failed,

2004, sea

bed wire

corroded

Line 2,

buoy chain

cracked &

replaced

Line 3,

buoy chain

failed

Line 10,

shackle

buoy

failed,

2001

Line 1,

shackle

buoy

failed,

2004, sea

bed wire

corroded

Line 2,

buoy chain

cracked &

replaced

Line 3,

buoy chain

failed

Figure 10-16 - Example of Mid-Line Buoy Failures on a European FPSO

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10.4 Line Run Outs and Quick Releases

A complete mooring line run out from the turret of a North Sea FPSO occurred during the course of this JIP. The line back to the bitter end shackle was whipped out of the turret and fell down to the sea-bed. It was a serious uncontrolled incident which could easily have lead to a serious injury or a fatality. There was an added danger of damage to sub sea assets. Again semi sub drilling units have suffered from chain run outs and thus this was not a known failure mode. Figure 10-17 illustrates the damage done to one of the chain gripper chocks.

The following list of operations chronicles the events leading up to the failure:

Raised hydraulic oil pressure to approximately 250 barg.

Chain load was taken on the gripper and the chain rose up to remove load from stopper.

Opened the stopper and the chain was pulled up by fully extending the lift cylinders.

Attempted to close the stopper but was not possible because the stopper was contacting chain link. The operator considered that either tensioner was not fully extended or that chain links were too long.

The chain was lowered and the exercise repeated, but it was still not possible to engage the lower stopper.

Whilst lowering the tensioner a loud noise occurred and operator thought that chain was slipping through the tensioner and ran for cover.

Due to dust from the chain being detected by smoke detectors, a platform general platform alert (GPA) occurred and all personnel were mustered. The FPSO was shut down until an ROV could be mobilized through fear of damage to risers and other mooring lines.

Late Design Changes and Subsequent Modifications

The design of this particular mooring system was revised during the latter stages of fabrication. This was a result of further load cases which required a stronger mooring system. This was identified when the turret fabrication was well advanced. Thus, with the positions of equipment fixed, compromises in the design were made. Critical to these were the relative position of the tensioner to the chain locker spurling pipe which had the effect of fixing the size of the gypsy wheel and therefore the number of pockets in the wheel - see Figure 10-18. Also the tolerances of forged chain links had not been properly taken account of. Modifications to the lifting and locking mechanisms should prevent another incident of this type occurring. It is worth noting that line run-outs are far from unknown on semi-submersible drilling rigs [Ref. 45] and OTO 98086 [Ref. 46].

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Figure 10-17 - Gripper chock showing chain damage

Figure 10-18 - Upper Gypsy Wheel Arrangement before Failure

Figure 10-19 - Gypsy wheel structure after failure, i.e. Gypsy Wheel No Longer Present

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Chain Run out Implications for the Industry

The Manufacturer of the Linear Tensioner assembly which failed has confirmed that this FPSO is unique in its use of a combined upper gripper and lower stopper assembly in one installed unit. BUT this does not necessarily mean that there is no danger of possible chain run out on other units which are able to adjust mooring line tensions.Hence the lessons learnt need to be distributed through out the industry. This incident highlights the importance of reviewing all similar mechanical systems to check that, during the course of a long period of operation, chain/stopper wear or link dimensional variation may not jeopardize the integrity of the mechanism.

10.4.1 North Sea FPSO – Repair of Loose Studs

On an early North Sea FPSO it was discovered that a number of mooring lines had loose studs. The lines were repaired with a new design of kenters (see Figure 10-20). However, at present the classification society is stating that, despite the expected superior fatigue performance of these kenters, they will still need to be examined in the dry after 5 years service. Recovering kenters on to the back of an anchor handler, so that they can be dissembled and examined, is a major cost. Since kenters themselves are not that expensive relative to boat time, it makes sense to replace any kenters which have to be recovered for inspection. The replaced kenters can then be examined in detail back on land to evaluate whether there is deterioration or cracking. If this shows that the new improved fatigue life kenters have behaved well in the field, there would be more of an argument for leaving them in situ for longer between inspections.

Figure 10-20 - Illustration of a New Design of Kenter Shackle intended to have improved Fatigue Performance

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As FPS units get older, the desirability of repairing lines using components, such as kenters, which are as similar as possible to common link chain, will increase. Hence, it will be important to record the performance of all new designs of kenters both on FPS and semi submersible applications. Since flotels and drilling semis recover their mooring lines regularly this should give increased scope for inspection compared to a permanent FPS mooring. It is worth noting, however, that at present no type of kenter is permitted to be part of a permanent mooring system in the Gulf of Mexico.

10.5 Windlass Failures

This incident relates to a South China Seas production semi. Eleven mooring lines made of 5 inch spiral strand wires and 4.75 inch chains moor the semi. The windlasses, by paying in and out of the upper chains, are used to adjust the position of the semi over the subsea trees. In the early phase of the project the wells were batched drilled and completed. This led to a significant chain mileage. A year after first oil, one of the windlass wheels started to wobble. A closer inspection discovered that the windlass wheel was split into two pieces by a circumferential crack, see

Figure 10-21. Inspection of the other wheels indicated similar damage. Since the windlasses could not be used, all the chains were locked on the chain stoppers. The wheels were not of a standard design. The wheels designed for a 5¾ inch chain had been modified to accommodate two chain sizes: 5¾ inch and 3 inch. The 3 inch chain was used to pull in the 5 inch mooring chain at installation. An additional circumferential groove had been machined in the wheel to accommodate clamps between the 3 inch to 5¾ inch chain. The roots of the main wheels were squared up to accept these clamps. The circumferential groove had no fillet.

Figure 10-21 - Example of Windlass Crack (Red Arrow) due to Stress Raiser caused by Sharp Corner (courtesy of BP)

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An important principle of practical design is the scrupulous avoidance of sharp corners or other "stress raisers" if there is any suspicion of alternating stress. So the cause of the failure was the stress raiser. Two independent fatigue analyses were made that showed the wheel could not have failed even with the bad fatigue detail. Further investigations revealed that the chains were not being locked off by the chain stoppers when the chains were not being adjusted, thus increasing the wave cycling loading on the wheels. Including the wave and wind tension cycle damage continuously was still far from sufficient to explain the failure. Knowing the answer the investigators dug deeper and added to the fatigue estimate the damage caused by the wheel rotation under the chain load. The rotation fatigue damage greatly exceeded the environment fatigue damage and “easily” explained the failures. New wheels without the groove were air shipped to Hong Kong and installed. The windlasses have operated without problem since then.

It is perhaps significant to note that fatigue damage caused by wheel rotation under chain load is not typically evaluated.

10.5.1 Operator’s Conclusions from this Incident

The following summarises the Operator’s conclusions from this incident which are informative from a mooring integrity point of view:

1. One of a kind designs or modifications of old designs sometimes fail prematurely.

2. When one designs a first-of-its-kind system that is critical to the operation of a one billion dollar facility, one should make the design “robust”. There are many ways to increase robustness. One very effective way, and practically free in comparison to the consequences, is to remove all stress raisers and all bad fatigue details.

3. Experienced specialists should perform detailed reviews of the design and finished product.

4. In a one of a kind design there are many “unknown unknowns” that may load the system in unanticipated ways.

5. Failure investigations should be well publicised to help educate others - part of the purpose of this JIP!

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11 SPARS AND OFFLOADING BUOYS (CASE

STUDIES)

11.1 Brent Spar Buoy

The Brent Spar Buoy, although now famous for the nature of its abandonment, was a successful design from a mooring integrity point of view. It had a 19 year operational life and minimum wear was found on the chains at the stoppers when they were examined when the Spar was cut up in Norway, see Figure 11-4 and Figure 11-5 . The MBL of the IWRC wire rope was found to have had no loss of strength when break tested after the line had been recovered – see Figure 11-6. Indeed if the strength had changed at all it had marginally increased.

Figure 11-1 - General Arrangement of the Brent Spar Mooring System (courtesy of Shell)

Brent Spar’s motion characteristics are probably significantly better than either a semi- sub or a FPSO. Loop currents do not occur in the North Sea and hence vortex induced hull vibration on Brent Spar does not seem to have occurred, unlike some Gulf of Mexico Spars. Brent Spar is interesting in that, relative to most FPSO designs of today, there were no trumpets or hawse pipes to guide the chain into the stopper. Figure 11-3 and Figure 11-2 show the fairlead arrangement used on Brent Spar.

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The chain is likely to have been pre-rigged which would have made things easier in the field, but this meant that a kenter was introduced at the connection. Thus this does not seem to be a particularly desirable solution for a long-term moored FPSO. Still it would be good to find a way of lining up chain in a stopper without using trumpets and angle iron as a guide, since these items can cause problems over time, see Section 9.2.

It is believed there was one mooring failure on Brent Spar, but this was at a kenter connecting link. Such a failure is not surprising, since standard kenters are known to have low fatigue lives. There are, fortunately, now new designs of kenters with improved fatigue lives, but these still do not at present have classification society approval for long-term mooring – see Section 10.4.1. In addition, one of the Brent Spar mooring lines got damaged by an anchor line from a drifting vessel.

Figure 11-2 - Brent Spar Fairlead Chain Stopper in the Hull (courtesy of Shell)

Figure 11-3 - Close Up of the Stopper (courtesy of Shell)

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Figure 11-4 - Indentation from where the chain bore down on the Stopper (courtesy of Shell)

Figure 11-5 – Red Arrow Illustrates wear on the chain, where it sat on the stopper (courtesy of Shell)

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Figure 11-6 - Brent Spar Wire Sample Y1 prior to cleaning [Ref. 41]

11.2 Floating Loading Platform (FLP)

The FLP illustrated in Figure 11-7 is continuing to enjoy a 12 year deployment in the Northern North Sea. During this time no problems have been experienced with the mooring system. What is perhaps significant about the FLP is that the trumpets when the chains come into the platform are short – see Figure 11-8. In addition, this unit was fitted with simple, but reasonably accurate inclinometers (see Figure 17-4). Micro ROV inspection of such inclinometers, in calm weather conditions, can identify if the lines are intact and whether or not a breakage could have occurred in the mud.

Figure 11-7 – FLP Mooring General Arrangement (courtesy of Shell)

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Figure 11-8 - Example of Short Trumpets on a Long Term Moored Floating Loading Platform (courtesy of Shell)

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12 TURRET MECHANICAL IMPLICATIONS FOR

MOORING INTEGRITY

12.1 Introduction to Turrets and Failure Modes

Turrets are reasonably complicated mechanical constructions which are subject to the following :

A long service life with limited opportunity for in depth inspections while deployed.

Regular fatigue loading.

High storm loading.

Gradual wear of bearings, gripper/locking units, etc.

There are numerous different types of turret, some of which are driven and others are freely weather-vaning. Turrets can be located at different positions on a FPSO and this tends to influence the turret type. Active turrets are supported on sliding bearings while other suppliers tend to use wheels or rollers. Table 12-1 summarises the advantages and disadvantages of the two bearing approaches [Ref. 48].

A key concern from a mooring integrity point of view is if the turret fails to rotate which could result in the FPSO becoming partially or totally beam on to survival storm conditions. This may well lead to twisting of the mooring system which could cause damage.

Active or driven turrets are not normally at the bow or the stern of a FPSO. Thus such systems tend not to naturally weathervane. Hence, the FPSO’s thrusters combined with the turret’s turning and locking system are used to turn the FPSO so it stays head on the weather. It can thus be appreciated that an active turret is probably more susceptible to FPSO power loss than a naturally weather-vaning turret. In practice “blackship” or no power conditions have occurred in the past on active turrets which have led to the FPSO being exposed to beam sea conditions. What is significant from a mooring design point of view is that FPSOs with turrets are not analysed for survival beam sea conditions. The wave frequency motion of a FPSO exposed to survival beam sea type conditions will be high and in certain cases this could lead to extremely high mooring line tensions. As well as blackship conditions active turrets can also be susceptible to thrusters coming out of the water in extreme storm conditions. In such cases if has been known for the thrusters to race in air, overload and trip. Even temporarily losing a thruster in the middle of a storm is undesirable.

Good references for turret behaviour in the field are HSE Offshore Technology Report 2001/073 [Ref. 47] and “Turret Operations in the North Sea: Experience from Norne and Asgard A” [Ref. 48].

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From a mooring integrity point of view the key points for the two different turret systems seem to be as follows:

If the active turret turning system or power supply fails or is operated wrongly there is a danger that the FPSO could end up broadside to the waves. However, the turning system includes redundancy, for example two of the four cylinders have sufficient capacity to turn the turret, even for maximum friction. These need to be designed for good access for servicing and repair.

For the passive turret if the bearings fail and the turret seizes up there is a danger of ending up broadside to the weather. A serious failure may require talking a FPSO off station to dry dock. Depending on location, even in an emergency it will take several days or weeks to put in place arrangements to take a FPSO off station. Hence the FPSO could have to ride out storms broadside to the weather, condition which the mooring lines are typically not designed to be able to withstand. The probability of complete bearing is likely to increase with age. It would be interesting to know what level of bearing deterioration has been noted when FPSOs have been removed from station at the end of a particular assignment. A related point is how quickly these systems can deteriorate if, for some reason, there is inadequate lubrication.

Active turrets do not utilise the turret turning and locking systems all the time. Instead the system is only activated when the turret has absorbed about 7 degrees of twist. This is different to passive turrets and hence it will be interesting to see if this results in any different wear mechanisms than active turrets. In actual fact this will be difficult to differentiate since passive turrets tend to be stoppered off at the base of the turret while active turrets have a gypsy wheel arrangement at the turret base. Wear at the gypsy wheel may be more similar to that which is typically encountered on a semi submersible submerged gypsy wheel fairlead.

Recommendation

A check should be made on a typical FPSO to see how great the increases in line tension are if the vessel cannot weathervane and thus has to ride out a storm broadside to the weather.

12.1.1 Line Tension Behaviour over Time

An interesting question is whether on active turrets the mooring line tensions have decreased over time due to straightening of the chain on the sea bed? On two Norwegian FPSO the line tension monitoring has not revealed any tension values close to the maximum design values. The line tension has not been found to decrease (or increase) significantly during the first years of operation.

Fatigue cracking was experienced on the grippers of a Norwegian FPSO at a stress hot spot. All grippers on this unit have been upgraded to improve their fatigue performance by removing the sharp notch.

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Sliding Bearings Roller Bearings

Advantages Extremely high vertical load capacity

Redundant system allowing partial repair or substitution

Stable turret position

Minimum wear on swivel

Wide fabrication tolerances

Adapts to vessel deformations, hence promotes a central turret position with minimum riser loads

Passive system requiring no daily operations

Promotes passive weathervaning, hence suitable for vessel with limited or no thrusters

Less risk of human errors

Disadvantages Active turret turning system needed

Daily turning operations

More frequent maintenance

Risk of excessive twist in case of turning system failure or faulty operation – possibility of uncontrolled twist back. This may happen if the torque from the mooring system overcomes the frictional torque from the bearings.

Non redundant system (failure leads to “Stuck Turret”)

Greater wear on swivel due to frequent rotations

Small fabrication tolerances

Vulnerable to vessel deformation

The forward turret position gives riser to higher riser motions and increased mooring loads

Table 12-1 - Summary of the Pros and Cons of Sliding and Roller Bearings [Ref. 48]

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12.1.2 How Marine Issues fit in with Normal Operations

It is important to be aware that turret operation/mooring behaviour is normally a secondary task for control room operators. Their main task is to keep the topsides process plant running and optimise the production of oil and gas. Given the importance of moorings it is vital that regular emergency drills are undertaken to keep training up to date.

On one Norwegian FPSO, to achieve optimum ventilation of the vessel topsides facilities the vessel is normally orientated against the weather with the wind approaching on the bow port side. This will tend to result in a slight corkscrew motion, which over time could influence the wear/fatigue behaviour of the mooring system.

It is important to understand that a Floating Production Platform is the whole hull plus process equipment plus risers and moorings. Thus the whole system needs to be considered as one inter-related unit. This is somewhat different to a fixed structure where the supporting structure is highly unlikely to suffer from progressive failure.

12.2 Implications of Mechanical Repairs

Turrets and thrusters are mechanical systems which are typically operating for an unusually long period of time in harsh environments. The option for dry dock inspection is not normally available and on going production operations may limit when and how inspection can be undertaken. Turret or thruster mechanical repairs can have safety case implications and any repair operation can be difficult and potentially dangerous. The following extract gives an idea of what can be involved in repairing a thruster in situ.

“Faced with removing a 13 ton thruster motor from deep within the bowels of the vessel and transporting it to the beach for overhaul onshore, the team instead chose to dismantle thruster 2 in-situ onboard the FPSO.

There were significant safety concerns regarding the removal of the motor in its entirety. The lifting route involved a 15-foot vertical lift, cross-hauling through the bulkhead hatch with only 90mm clearance in winter sea conditions, lifting over thruster 1 and a lift through an engineering space of 90-foot to reach the main deck. Due to these safety concerns, a safer and better method was needed to achieve the overhaul. The eventual solution was to strip down the motor into manageable pieces, onboard the FPSO, and to remove the rotor and bell housing for repair onshore. On completion of the repair, the rotor and bell housing were successfully reinstated using state-of-the-art technology from specialist vendors to realign the motor onboard. The entire process was achieved without any disruption to production.”

Active turrets also make use of computer controlled systems. Issues can arise of computer/software obsolescence. This needs to be taken account of in the planned maintenance system.

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13 GENERAL TRENDS AND STATISTICS

13.1 Questionnaire Process

A custom designed questionnaire was developed to undertake an international survey of worldwide FPS operations including FPSOs, production semis and Spars. A typical custom designed questionnaire is included in appendix B. The questionnaire is based on an Excel spreadsheet based with drop down boxes in an attempt to make completion as quick and easy as possible. The questionnaire was partially filled in making use of information in the public domain before emailing to Operators and Contractors. If the answer to certain issues is yes a standard series of questions are generated in a new worksheet. A filled out example is also included as part of the spreadsheet.

A. GENERAL DETAILS

A1. Unit Name A2. Field Name

A3. Unit Type

A4. Water Depth m A5. Geographical Area

A6. Date Installed

A7. Is the FPS classed?

A8. Has the unit ever been used elsewhere?

A9. Was the unit ever removed from site and then re-installed?

A10. Can the mooring system be disconnected in case of typhoons or ice bergs ?

A11. If the moorings can be disconnected, how often has this happened to date ?

JOINT INDUSTRY PROJECT: FPS MOORING INTEGRITY

QUESTIONNAIRE

Kuito FPSO Kuito, offshore Angola

Spread FPSO

383 W est Africa

Sep 1999

Classification Society: ??????Yes

No

No

No

N.A.

Table 13-1 - Example of the First Page of the Questionnaire – see appendix B for a Full Listing

The questionnaire is now available in the public domain and it is hoped that the format for reporting incidents will continue to be of use to the offshore community after the completion of the JIP.

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13.1.1 Difficulties Obtaining Data

Initially it was hoped that offshore personnel would be able to complete the majority of the questionnaires. Despite considerable time spent preparing and chasing up questionnaires and the ease of email communication, it became clear that the questionnaire was not given a high priority by hard pressed offshore and office based personnel. A degree of past knowledge is necessary to complete the questionnaire properly and with personnel change outs on units this knowledge can easily get lost.This is itself is a somewhat worrying result for such complicated production facilities.

Getting detailed information on units operating outside the North Sea was particularly difficult. The problem was not necessarily lack of interest, just a lack of time with operational issues taking precedence. It is noted that good data could be obtained by visiting FPSs and auditing the condition of the set up of their mooring systems and reviewing inspection records. Quite often there is reasonable data available and the key problem is gaining access to this data which may not be centrally stored.

Although it was difficult to get data on as many units as initially hoped, the data which was obtained was in general of high quality (see Case Studies) and is believed to be pof relevance to the vast majority of FPSs in the world today.

13.1.2 International Survey of FPS Experience

Types of Units and Geographical Location

The international survey has been an important part of the JIP. The approach has been to collate data in a similar fashion to the “UKOOA FPSO study” but extending it to the worldwide fleet of FPSOs, Production Semi submersibles and Spars. Mooring performance will depend on the type of unit considered and the environment which it is exposed to. The following generic types have been considered:

North Sea turret moored FPSO

North Sea Semi-sub FPS

West African spread moored FPSO

Brazilian deepwater FPSOs (turret and spread moored)

Brazilian Semi-sub FPS (very limited data received)

Gulf of Mexico Spar

South East Asia FPSO

Special FPSOs e.g. dis-connectable and ice resistant

Worldwide FSU (limited investigation)

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13.2 Summary Statistics for Unit Type and Geographical Area

The following graphs summarise some of the more reliable and significant results obtained from post processing the returned questionnaires. Only statistics where a reasonable sample size was acheievd have been reported.

North Sea Turret Moored FPSOs

Adjustable Line Lengths

Lines

Locked Off

50%Can Be

Adjusted

50%

Real Time Offset Monitoring

Units with

67%

Units

witho ut

33%

Real Time Line Tension Monitoring

Units with

50%

Units

witho ut

50%

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Line Failure Alarms

Units with

22%

Units

witho ut

78%

Mooring Line Spares

Units with

33%

Units

witho ut

67%

Existing Repair Procedures

Units with

13%

Units

witho ut

87%

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It is interesting to compare the average mooring line inspection periods for various different types of FPS units in different locations. This is illustrated in Figure 13-1.

1.21.6

5

0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

5

Years

Average Inspection Periods

North Sea Turret Rest of World Turret Rest of World Spread

Figure 13-1 - Comparison of Mooring Line Inspection Periods for Different FPS Categories

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13.3 HSE UK Sector and Norwegian Statistics

Interrogation of existing health and safety databases provided useful validated data – see Table 13-2, Table 13-3 and Table 13-4.

96/97 97/98 98/99 99/00 00/01 01/02 Total

Moorings/DP 0 0 1 2 1 3 7

FPSO/FSU Total

Incidents

11 10 15 22 10 11 79

Mooring/DP percentage of FPSO/FSU incidents

0% 0% 6.7% 9.1% 10% 27.3% 8.9%

Table 13-2 - UK Sector of the North Sea Data [Ref. 49]

Period 1980 to 2001 (ORION database)

Drilling Semis Production Semis Accommodation

Semis

FPSO’s

N F N F N F N F

Anchor

Failure

170 0.211 8 0.111 23 8 0.113

Table 13-3 - UK Sector of the North Sea Data [Ref. 49]

Where N = number of events and F = occurrences per unit year. Anchor failure defined as “Problems with anchor/anchor lines, mooring devices, winching equipment or fairleads (e.g. anchor dragging, breaking of mooring lines, loss of anchor(s), winch failures.”

Incident Description Mobile Drilling Units Production

Single Failure 9 3

Multiple Failures 3 -

Table 13-4 – Number of Anchor Incidents in the Period of 1990-2003 in the Norwegian Sector [Ref. 50]

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Even though considerable resources have been devoted to the international survey, it is quite possible that that only a fraction of the total number of mooring incidents which have occurred outside of the North Sea have been reported. In the North Sea there are statutory requirements for mooring incidents to be reported to the UK Health and Safety Executive (HSE). Although the North Sea is a hostile climate, units intended for use here are in general designed to a high standard. In addition, a number of the units in the North Sea have been around long enough for age related problems to start making an appearance. It thus seems prudent to consider official statistics for this region to be a reasonable indicator of the likelihood of mooring line failure.

These statistics indicate that it would not be totally unexpected for the crew on a FPS to expect a mooring line failure sometime during a field life which exceeds 9 years. Exactly how these statistics can be related to milder environments is difficult to estimate without access to more data. But it is worth noting that but fatigue may be more of an issue for milder locations - see Figure 15-11.

This concern that offshore staff on a FPS should always be prepared and ready to react appropriately in case of mooring line failure is reflected in the following quote from from Ref. 3. Although the background of this paper is mooring operations of semi-submersible units, the basic sentiment is felt also to be appropriate for FPS units in general.

“The high failure rate of individual mooring lines means that a unit must always be prepared to deal with a mooring line failure as an almost routine operational matter. It is unrealistic to operate a unit on the assumption that a mooring line failure is unlikely to occur.”

It is not perhaps surprising that when FPSs first became more prevalent that their mooring systems suffered some initial teething troubles as new designs were introduced. These early problems seem to have been largely resolved and thus in general terms one might expect a plateau period of mooring failures. What will be interesting to see is how the number of failures increase as the mooring lines age and are subject to corrosion, wear and fatigue.

As a FPS operator, it is probably helpful to think in terms of average historical line failure rate per FPS unit operating year.

Figure 13-2 illustrates historical failure rates for different types of North Sea units. The failure rate for FPSOs is closer to the UKOOA study reported value of once every 5.4 operating years. Given that North Sea designed FPSOs are carefully regulated it would be expected that the reliability of these units should be good. Hence it is disappointing that the failure rates for FPSOs is only slightly better than production semis and only about twice as good as a drilling semis.

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NDE’s UKOOA report referred to DNV’s data for 1980 to 1998, which reported 7 FPSO/FSU anchor system failures. This gave 0.186 failures per unit operating year or one failure every 5.4 operating years. Hence, it can be seen that the failure rate seems to have improved somewhat from 1998 to 2001.

Comparison of North Sea Failure Rates for Different Unit Types (1980 - 2001)

0

1

2

3

4

5

6

7

8

9

10

Drilling Semi Production Semi FPSO

Type of Unit

Nu

mb

er

of

op

era

tin

g y

ea

rs p

er

fail

ure

Figure 13-2 – Historical Failure Rates for Different Types of Units

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14 CONNECTORS AND TERMINATIONS

14.1 Background

Connectors and line terminations (e.g. spelter sockets or fibre rope splices) are vital components in a mooring system, since they are typically necessary to join up different types of line e.g. chain to wire, or to suit manufacturing/transportation limitations on line lengths. However, the need for some type of opening and closing mechanism means that, to achieve the required strength, the connectors tend to be heavier than the lines to which they are attached. Thus connectors and line terminations tend to be areas of discontinuity on a mooring system with respect to weight per metre and also bending and torsional stiffness. This is because they are unlikely to flex in the precisely the same way as the chain, wire or fibre rope to which they are connected.

In general, where there is a weight discontinuity on a mooring line there is an increase in relative rotation. This rotation can result in wear plus possibly some fatigue loading. Yet it is typically fairly difficult to inspect connectors in situ for wear – see for example Figure 18-15. Hence, due to the long-term effect of these degradation mechanisms, failures have occurred – see for example Section 10.2 and the problems associated with traditional Kenters, Baldt, Pear and C Links on drilling rigs.

The design of chains and wire rope does not tend to change dramatically from one project to another. This is not necessarily true of connectors which may need changes for new applications. Hence this section attempts to summarise what connectors and line terminations are available at present. It then goes on to consider what should be taken account of when designing new connectors – see the flow diagram in Section 14.3. The section concludes with any gaps in the existing knowledge base and identifies topics which merit further investigation.

14.2 What Type of Connectors Can be Considered for Long Term Mooring

(LTM)

Class Societies typically have special requirements for Long term Mooring (LTM) systems. For example DNV applies this categorisation for mooring systems which will be at the same location for more than 5 years. LTM ‘D’ shackles typically have a double locking mechanism, such as a nut and locking pin restraining the primary restraint system, see for example Figure 14-10.

The following section reviews the type of connectors which are fairly readily available and might be considered for a long term mooring.

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14.2.1 Traditional Kenter

The traditional design of Kenter link dates back to a 1905 patent by Max Kenter. The patent description is as follows :

“Improvements in Chain Coupling-links - A coupling-link for chains consists of two similar parts a, b, which are adapted to engage laterally and are locked in their engaged position by the grooved piece f. Movement of the piece f is prevented by the inclined taper-pin h secured in place by the lead plug i.” [Ref. 52].

The great merits of a kenter are that it can pass through a gypsy wheel in the same way as normal chain and its dynamic behaviour is very similar to chain, since it is of comparable weight and geometric arrangement. If kenters are tight fitting and are properly assembled with a lead plug added after assembly, they can perform quite well. For example some drilling rigs end up with kenters in the thrash zone and these can last quite well for a temporary application. Still assembly tolerances vary in practice, and thus having a kenter in the thrash zone should only be considered as a temporary repair. Kenters are discussed in more detail in Section 10.4.1. It should benoted that if the lead plug comes out in service there is a danger that the kenter could open up.

14.2.2 Special Joining Shackle (SJS) and Shackle Pin Rotation

A SJS can be used to connect studless common link chain to studless common link chain without the need for an enlarged end links, which would typically be required if a normal shackle were to be used. Enlarged end links can only be added to a chain at a Forge so their inclusion reduces flexibility with regard, for example, to trimming chain during line hook up operations.

The bow of a SJS needs to be trimmed compared to a standard D shackle to allow studless link connection. To qualify for LTM designation typically a double locking mechanism for the shackle pin is required, as well as a demonstration of fatigue life. In addition, the same quality material is typically used for the shackle body, pin and locking nut.

In the design illustrated in Figure 14-1 the pin of the shackle is oval which means that it normally cannot rotate in the shackle body. Normally when two chain links rotate against each other the surface profile and the harness for the links is very similar. However, when a chain is connected to a SJS the surface hardnesses of the chain link and the shackle, as well as the geometry may be somewhat different. If the combination is such that this leads to accelerated wear of the chain link, which is of thinner section than the shackle, then this could lead to early loss of integrity. In addition, due to the weight discontinuity it is likely that there will be more relative rotation between the link and the joining shackle.

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Whether or not to allow pin rotation on a connector is a difficult question to answer. In the case described in Section 10.2, the initial approach adopted to preventing pin rotation was not strong enough and ultimately failed. The solution was to allow the system to rotate and using a much stronger mechanism to keep the end plates in position. For the H shackle illustrated in Figure 14-2 the pins are oval where they pass through the shackle body. This is needed to make them small enough to pass through the chain links. However, the holes in the H shackle body are round. This allows the oval pin to rotate in the H shackle body. Since the H shackle body and pin are oversized any wear in these components should not be significant. But it is important that wear in the attached chain link should be minimised, since when it moves it should not be grinding against a fixed, not rotating surface (pin).

Some precautions are possible; for example the shackle shown in Figure 14-2 had its pins specifically fitted to the chain links and a set of baseline pin angle measurements were taken using photographs so that they can be compared in the future to ROV photographs. Whether this logic proves to be demonstrated in practice will only become clear over time!

Figure 14-1 - Special Joining Shackle (courtesy of Vicinay Catalogue)

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Figure 14-2 - “H” Shackle Pin Configuration (courtesy of I. Williams)

Other Types of Connectors

Other types of subsea connectors are illustrated in Figure 14-3. Requirements for subsea connectors are discussed in more depth in section 6.2.4. More temporary types of connectors include Baldt or C connectors and pear links. Sometimes these are “a rattling good fit” and the general perception is that they fail more often than kenters. They should not be considered for long term mooring systems, even for temporary fixes, unless they are all that is available. Standard kenters are better machined, “fit tighter” and are more suitable for a short term repair.

Subsea

Connector

(Delmar)

Female and Male being assembled

Female Male

Designed to

facilitate

connection &

disconnection

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Subsea

Connector

(Ballgrab)

Designed to

facilitate

connection &

disconnection

Figure 14-3 – Illustration of Subsea Connectors which have been used on Pre-Installed Mooring Lines

Figure 14-4 - Example of a Special Joining Plate - Note Electrical Isolating Bush

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14.3 Terminations General

To be of practical use a rope must be provided with means for connecting it at its ends into the mooring system. The task of the termination is to transfer the predominantly axial load in the rope into an engineering component which can be attached to standard mechanical/structural components which form part of the platform being moored.

Nearly all rope terminations depend to some degree on developing radial forces - and through them friction - to allow the axial load in the rope to be transferred to another element. The splice is the basic example of this in which, when the rope is placed in tension, the geometry of the splice generates radial loads between the rope strands and these allow sufficient friction forces to be generated to transfer the load from one strand to another. In other terminations the radial forces are generated by means of a mechanical device.

It is well documented that during break or fatigue testing many rope specimens are seen to fail at or very close to the terminations. This is due to the additional stresses introduced into the rope at or close to the termination.

The termination components may have to support many other additional loads, such as bending and shear, other than the axial load in the rope. Finally the termination may have to survive abrasion, fatigue and corrosion.

14.3.1 Spelter Sockets

Splicing of wire ropes is complex and difficult on account of the weight and stiffness of the large size of typical mooring ropes. An alternative which has developed is the use of the spelter socket (see Figure 14-7) in which the rope is inserted into a metal collar with an internal conical hole. The wire rope is cleaned and teased out to form a brush which adopts the internal conical space of the termination. Into the cone is poured a molten spelter alloy which solidifies and acts to grip the wire when it is pulled.

Figure 14-5 – Example of the Make Up of a Typical Closed Spelter Socket (courtesy of Bridon)

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Wire rope terminations or sockets can be either open (Figure 14-6) or closed (Figure 14-7).

Figure 14-6 - Example of an Open Socket

Figure 14-7 - Example of a Closed Socket

An alternative to using spelter alloy for terminating wire ropes is to use an epoxy resin. This has become a popular and efficient method of terminating wire rope. Potted sockets have the advantage that they can be applied in the field if necessary without the complications of providing a means of melting the spelter alloy.

The potted resin socket has also been used for terminating fibre ropes. As in the case of wire rope the end of the rope is inserted into a socket and the yarns/strands splayed out. A compound such as epoxy is then used to fill the socket which, when it sets, forms a strong bond to the fibre material and socket. Conventional wire rope sockets have been used successfully on small aramid ropes.

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Although epoxy potting has been used for some small size fibre ropes it has not proved effective for larger ropes due to the difficulty in providing sufficient circumferential area over which to distribute the shear loads needed to carry the axial load out of the rope. Solutions have been proposed in which the rope is divided into component strands each with its own potted termination but so far the complexity of this approach has been a major obstacle to its use.

It is important that, when being prepared for potting or speltering, a rope must be accurately set so that the termination is not at an angle to the axis if the rope. If this happens the rope will be subjected to a degree of bending when the load is applied and this can seriously weaken the capacity of the rope. This effect is particularly apparent when only a short specimen of rope is being terminated as in such cases the limited length of the rope means that the uneven loading over the rope cross section has less chance of being absorbed in the stretch of the rope. This leads to a concentration of bending effect and earlier failure. This can be particularly important when preparing short specimens for prototype testing.

14.3.2 Spelter Socket Fatigue Assessment (S-N curves) + Bend Limiters

At present during detailed design S-N curves for common link chain seem to be often applied. This is not really appropriate and requires further consideration on live projects.

The Bend stiffener and attachment mechanism also needs to be suitably designed, see for example the damage shown on Figure 6-6.

Other areas to consider for sockets include:-

- the potential for pin rotation,

- the need for anti rotation keys,

- whether or not the spelter sockets are in a vertical orientation.

If the spelter sockets are not vertical they will be subject to cyclical bending stresses, which over time might cause a fatigue problem, depending on their design. It is also important to be able to check whether the insulating PTFE bushes are present or not.

14.3.3 Fibre Rope Splices

This is the prevalent form of termination for fibre ropes throughout the industry. There is a large degree of experience available when considering terminating large diameter fibre mooring ropes with eye splices. Other techniques (Grip and Potted) are much less well documented. A splice in a polyester rope has been shown to have an efficiency approaching 1.00, depending on the quality of the splice. It should be noted that the certified minimum break load (MBL) of a fibre rope is that of the spliced rope ([Ref. 53] or OCIMF hawser guideline).

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Splicing has been described as an ‘Art’; there is a movement within the rope industry pushing for this to be changed to a ‘Technology’. There are papers which describe modelling of splices (see for instance Ref. 67) and recent offshore projects in the Gulf of Mexico have described various means of controlling and documenting splice production in ropes with a breaking strength in the region of 2,000 tonnes.

In terms of fatigue testing, most assessments have been made with splice terminations. Here the fatigue lives for polyester and aramid ropes are described as being well above that of steel wire rope at normal working loads.

For large diameter synthetic fibre ropes under long term cyclic loading the only verified technology for their termination is by use of a splice.

Two types of spliced eye hardware are described. The first is a construction involving a metal thimble and shackle arrangement which has been used successfully for years at single point mooring terminals. This type of connector is, however, described as making rope handling particularly cumbersome and awkward [Ref. 68].

To-date most offshore experience of large fibre mooring ropes has relied on this type in which the thimble can be slipped into a prepared soft-eye splice when the connection is being made-up on the deck of the mooring installation vessel. The thimble is supported by a shackle and provides a suitably large diameter over which the fibre rope can be bent. Advice on the choice of spool diameter is available from guidance documents such as Ref. 69. The thimble diameter should be large enough to develop the best axial tension and fatigue strength while minimising abrasion and wear as the stretching rope slides against the metal of the spool. In order to minimise this problem the splice eye is often wrapped locally with a binding tape in order to minimise wear on the fibre rope. When the line goes into tension the spliced eye pulls tight and prevents the thimble from falling out. However, during over-boarding when there may low line tensions and eccentric loads on the connection care must be taken to stop the line slipping-off the thimble and being caught on the shackle instead.

It is important that the fitting between the eye and the spool is tight enough so that the two do not become separated. This is described as being most likely to occur during rope handling when the rope is slack.

This is often achieved through encapsulating the thimble in polyurethane. However if the splice is provided with a permanently fitted hard eye in this way it means that there are additional problems when handling the rope on its transportation and deployment spools as the thimble must be prevented from abrading and damaging the rope on the spool.

Various novel terminations are currently being proposed and evaluated. These seek to improve the efficiency of terminations for very large ropes by splicing the sub-ropes individually to themselves to create a number of eyes. These are then supported on multiple pins. High performance materials (e.g. titanium or super duplex) are used in order to minimise the weight of the metal components.

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14.4 Connector/Termination Design Flow Chart

Figure 14-8 and Figure 14-9 together illustrate a connector design flow chart based on approaching the subject with a blank piece of paper. The flow chart is also generally applicable for the design of terminations. Comparing this flow chart with present day design practice shows that the following:

A wear analysis is typically not undertaken

The dynamic motion of the connector is typically not evaluated

Calculations are not typically undertaken to size locking pins based on high line tensions and frictional forces

Electrical isolation needs to be considered early on in the design process

Inspection is not given a high priority during connector design.

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Figure 14-8 - Connector or Termination Design Flow Diagram - Initial Phase

YES

UNSATISFACTORY

YES

NO

Could any existing

designs be used?

Asses the pros & cons of the existing

design & decide whether to proceed with modifications?

Develop a Design Brief specifying strength, fatigue life, installation weight, material

properties etc

NO

Obtain Client written approval of Design Brief

& Class agreement in principle

Quality Plan for design & manufacture to describe activities to be performed, frequency

and type of inspection/tests, criteria to be met as well as give reference to applicable controlling

documents

Submit Quality Plan for Class Approval

Requirement to join two lines

Assess the ease of deployment, including connection/disconnection & the likelihood of

unintentional disconnection

Identify what is special about the new application & propose a new design

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Figure 14-9 - Connector (Termination) Detailed Design Flow Chart

NO

Wear Assessment

- Proposed Methodology - Justification - Past Observation - Guidelines

- Codes

Fatigue Life Assessment

- Suitable S-N Curves - Stress Concentration Factors Identified? - Physical Testing - Hand/Simple Calculations - Tension/Tension Assessment - Tension/Bending Assessment - Cumulative Damage

Evaluation

Corrosion Assessment

- Avoidance e.g.Anodes - Allowance e.g.Corrosion Margin - Physical Testing - Past Observation

- Calculations

Strength Assessment

- Hand/Simple Calculations - Finite Element Analysis - Material Testing

- Physical Testing

Commence Detailed Design Process

Manufacture in accordance with Quality Plan & Class

Society inspections

Test Connector as per Quality Plan

Documentation to be stamped with Class

Approval

Issue Recommendations for Connector

Transportation, Installation & Long Term Inspection

Finalise Design Reports & Drawings; issue to Class

Society & Client

Design Iterations

Successful?

NO

YES

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14.5 Detailed Design Guidance

There are numerous different types of mooring line connectors depending on whether chain, wire or fibre ropes are being connected. Operational experience from a number of floating production and drilling units has shown that failures quite often occur at connectors. In certain instances the connectors have failed by coming undone when their locking mechanisms have failed, see Section 10.2.

To ensure the long term reliability of a FPS mooring system it is important that the design of ALL the proposed connectors in a mooring system should be carefully reviewed. This also needs to take into account where on the catenary and on the sea-bed the connectors are situated. The following general guidelines are provided for the design and selection of connectors:

Try to minimise connector weight to avoid increased rotation at each end due to an abrupt change in weight per metre of the mooring line.

Avoid placing connectors in the thrash zone.

Allow shackle or spelter socket pins the ability to rotate.

Add marks on connectors so that any wear can be measured.

Ensure connectors have compliance in all required planes of motion – see below.

Match material characteristics to minimise wear.

Pin locking devices need to take in to account applied loads and friction developed lever arms.

Secondary locking devices should be provided which are capable of withstanding the full anticipated loading in case the primary device fails.

Sharp edges where any pin is stepped down to the locking nuts should be rounded to minimise the danger of cracking occurring.

In general rounded rather than chamfered edges around the edge of the shackle should minimise damage if contact occurs with chain links.

It may be beneficial to put a groove in shackle/spelter socket pin to reduce point to point contact. In other words contact between the link and the pin would be similar to link to link contact.

Thought should be given on how to handle the connector given its weight. Welding lifting eyes on to it should be avoided.

The weight distributions of the connector, including the locking mechanism, should be balanced to ensure that it does not lie to one particular side.

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Depending on configuration/pre-tension as a catenary leg is laid down on the sea-bed and the sea-bed takes up the weight, the tension may drop down to zero. Hence if you have a heavy connector on the sea bed you can see a lot of rotation at this point and thus potential wear. Modern day dynamic mooring analysis programmes can assess if the lines are likely to go slack at any time.

Chain, wire and fibre rope can all rotate in numerous planes. However, most connectors have limited compliance and it is thus important to confirm that, where they are placed on a mooring system, they can allow the predicted motion without resulting in lock up and thus relatively sudden increases in bending stress. Figure 14-10 illustrates a purpose designed “X” shackle for connecting between studless common links at the base of a FPSO turret. In this case a dynamic analysis was undertaken to determine the required compliance in two planes and then the “V” in the “X” shackle was designed to suit, including a contingency factor, see Figure 14-2 and Figure 14-10.

When designing a connector the most appropriate proof stress should be assessed which will give a good fatigue life – see Section 14.5.

Figure 14-10 – Illustration of a Purpose Designed connector allowing limited compliance in Two Planes

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Figure 14-11 - Example of a Dynamic Analysis to Estimate the Angle for the “V” Slot Size on the “H” Shackle

Certain connectors, such as Long Term Mooring (LTM) D shackles, have been available on the market for a number of years and thus have established track records. Still it is prudent when selecting connectors to determine where they have been used before and if any problems have been identified. Even with an established track record, connectors must still be evaluated on a case by case basis, since different pretensions, vessel motions and position on the mooring line can affect their long term behaviour.

14.5.1 Forging versus Casting

From a mooring perspective castings are normally considered only suitable for mass produced, intricate items. For example, Wire rope sockets are cast because of their inherent elaborate design. Forging is the preferred method of manufacturing mooring accessories, since it helps to ensure that the items are strong but ductile. Impact strength is a key element in any mooring accessory design.

The following list details the advantages of forgings versus castings [Ref. 51] :

Higher strength

Unmatched toughness

Longer service life

Higher structural integrity (absence of internal defects)

Use of higher design stresses

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Greater transverse properties

Increased safety margin (due to high ductility)

Greater strength-to-weight ratio (lighter parts, reduced sections)

100% density (no porosity)

Higher overall quality / reliability

Reduced product liability concerns

More acceptable parts / fewer concerns

More uniform heat properties (lot to lot, and part to part)

Directional or isotropic property profile

More consistent machining (uniform microstructure and chemical composition)

Better hardness control for abrasion / wear resistance

Extended warranties more probable on critical part / assemblies

More versatile processing options and combinations

Option to optimise the grain flow directions of the component

14.5.2 Discussion of Connector/Terminations Type Approval

At present it appears that each Classification Society has their own rules and regulations for assessing whether a connector is suitable for a long term mooring application. It would be helpful if, perhaps under the auspices of IACS (International Association of Classification Societies), that a standard protocol could be developed for designing and testing these connectors/terminations.

14.5.3 Fatigue and Wear Assessment of Connectors

API RP2SK provides the following “Data for other types of connecting links (i.e. apart from Kenter or Baldt links) are insufficient for generating design curves. Limited data indicates that the fatigue life of D-shackles is comparable to that of common links of the same size and grade, provided that the shackle is machined fit with close tolerance, no cotter pin is used through the shackle body and the shackle is the narrow throat type.” Since spiral strand sockets are not D shackles or Baldt or Kenter links it can be argued that it is not valid to assess their fatigue performance using a S-N curve for common link chain based on API RP 2SK. However, this technique appears to have been used on a number of North Sea FPSOs.

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Apart for a few general types of connectors, such as kenters or Baldt links, specific S-N curves are not available. In such cases it is common practice to assume that the behaviour of a large, heavy connector will be superior to that of the chain or wire to which it is connected. Considering the cost associated with mooring failure or intervention, this is not a re-assuring situation in terms of long term system reliability. Hence it is important that a valid fatigue assessment is undertaken for each individual part of a mooring system. This should be reflected in the mooring design specification.

As is discussed further in Section 0, wear can be a significant issue over the life time of a mooring system. Where there is an abrupt change in weight per metre of a mooring line at a connector, greater relative rotation can be expected. This may not be too much of an issue for the connector itself which may be oversized. However, over the long term it may become an issue for whatever is connected up to the connector, e.g. common link chain. This should be assessed on a case by case basis and if considered to be a possible cause of concern, suitable analysis or testing should be undertaken.

14.6 Proof Load Testing and Its Impact on Fatigue

Chain strength is established by break and proof load tests. In a break test, a sample length of chain is loaded in tension to an estimated break load value which it is held at for 30 seconds without failure. The minimum breaking load specified is typically 75% of the stress level for the minimum ultimate tensile strength. The proof load test is nominally the highest load carried by the chain without deformation. The ratio of proof load to breaking strength depends on chain grade – see IACS W22 [Ref. 66]. In studded mooring chain proof load is about two thirds of its break strength. For example for setting the chain to its final shape and locking the studs into position, a proof load based on 90% of the load at minimum yield stress, or 78% of the minimum breaking load is typical.

The proof load concept needs some further refinement for materials, such as certain higher strength steels, which do not exhibit a particularly defined yield point. These materials initially respond under load with a linear elastic response but this gradually softens until the ultimate tensile strength (UTS) is reached. As no yield point can be used as a reference point, the concept of proof stress has been advanced, essentially as a material property, where the 0.1% proof stress corresponds to the stress from which a 0.1% strain permanent set would result following elastic unloading. Depending on the material, the proof stress (PS) may be defined variously as a 0.1% or 0.2% proof stress – see Figure 14-12 and Figure 3-34. From a materials perspective a proof test is to confirm that the degree of elongation under application of the proof load (stress) is not exceeded.

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Figure 14-12 - Example of Material with a Non Clearly Defined Yield Point

‘Proof loading’ of chain is carried out for a number of purposes including to check the stiffness (elongation) of chain and to ensure the studs are ‘fixed’ following heat treatment which otherwise relaxes the initial clamping forces applied. Proof loads are generally defined in codes and standards as a proportion of the minimum 0.2% proof stress or minimum UTS combined with the nominal section area.

Proof loading of the chain into the plastic range leaves a small permanent set when the load is removed. The component geometries means this induces locked in residual stresses in the chain and these are compressive at the inner shoulders of the links. This means that applied tensions have to reverse the residual compressive stresses before tension is induced in these fatigue prone areas and the proof loading may therefore be considered to be beneficial to fatigue endurance.

Evidence for this was obtained, inadvertently in the BOMEL JIP. The first two tension fatigue tests delivered extraordinary results and were halted, without evidence of cracking, when the predicted lives were exceeded by a factor of around three. In consultation with the chain supplier, it was concluded that the chain had been subjected to an excessive proof load during manufacture. It was noted that such treatment was allowed under the specification and the practice is not uncommon to stretch the chain when it is under-length.

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Amoco (one of the BOMEL JIP sponsors) proceeded to undertake further testing to assess proof loading effects on the fatigue life of chains, in conjunction with the University of Tulsa [Ref. 54]. A range of proof load levels was investigated (up to 82% of break strength) and it was concluded that proof loading substantially increases the fatigue life and this was attributed to the residual stresses generated. Importantly they noted that in addition to the level of proof loading, the ability of the material to sustain the residual stresses without redistribution under cyclic loading was another factor affecting the consequences for fatigue life.

A difficulty for high strength (e.g. R4) chain is that the proof stress is cited with reference to the minimum UTS/breaking load. If a batch has a significantly higher UTS (which in many senses is desirable), the degree of plasticity brought about at the proof load level may be significantly less than assumed with the minimum specification material. This means that the degree of residual compressive stress within the links will vary depending on the actual material properties. Furthermore with the high strength steels used for chain, the proof stress to UTS ratio can exceed 0.95, something that is generally precluded with a limit around 0.85 in steel for structural purposes. High actual PS/UTS ratios would further limit the degree of plastic deformation / residual compressive stresses achieved through the standard proof loading procedure.

A more consistent approach for specifying the proof load would be in relation to the batch UTS, something that is invariably tested.

Although the above discussion relates the effects of proof loading to the consequences in terms of fatigue performance, in the case of studlink chain appropriate levels of proof loading are equally important. If the degree of plasticity achieved under proof loading is less than anticipated, studs will be more likely to become loose in service.

The above discussion highlights the importance of:

Developing a more meaningful specification for effective proof loading during chain manufacture

Undertaking research (using finite element analysis and physical testing) to define any beneficial effect of proof loading of chain for fatigue performance and translating this into manufacturing specifications, as appropriate.

14.6.1 Break Testing Rate of Load Application

OTC paper 10798 1999 [Ref. 70] states on page 268 that a connector failed the minimum break load test because the rate of load application was faster than had been specified by the manufacturer’s test procedure. Another connector plate was tested using a slower rate of load application and passed the minimum break load test.

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This is of considerable interest since, depending on the slow drift offset of the FPS, a mooring system can experience very rapid increases in line tensions due to first order wave frequency response. As far as can be determined classification societies (including IACS) typically do not specify the rate of application of the break test load.Hence it is believed that this is a matter which requires further consideration, since intrinsically it is not desirable to have a means of testing which:

a) poorly replicates the offshore loading environment,

b) can lead to either a pass or a fail depending how the test is done.

Whilst performing a "real" scale test would be a rigorous/ideal way forward, it is unknown whether all the test houses / manufacturers would be able to undertake this for the larger sized items and more research is needed. In general the ramping period does not appear to be recorded unless specifically requested by reference to a manufacturer's or client specification. This seems a simple and informative piece of information which should, by default, be included in the as built documentation.

It is appreciated that failure through shock loading may be caused by brittle failure instead of the traditional tensile failures (necking). Therefore, one option may be to have more onerous requirements for impact tests or at lower temperatures. This may be of more particular interest with high tensile steels which may be more prone to the brittle failure due to defects / flaws. But still there is a need to correlate this back to the ramping speed break test performance of real connectors.

A4163-01 197

15 OUT OF PLANE BENDING – CHAIN AND ROPES

(FIBRE + WIRE)

15.1 Tension Bending at a Wildcat and its Effect on Fatigue

As chain is fed over a fairlead it is subjected to tension plus an out of plane bending moment resulting from the local geometry of the contact between chain link and gypsy wheel bearing surfaces. Fatigue issues associated with chain links in gypsy wheel fairleads have been reasonably well documented and incorporated in design practice (API 2SK RP2SK [Ref. 31] and DNV OS-E301 [Ref. 5] for example).

Despite this, failure of mooring systems continues to occur. Fatigue calculations are often restricted to links in the catenary, neglecting the reduced fatigue life local to the end termination. One North Sea unit suffered a link breakage at the fairlead, after only one winter.

Figure 15-1 Broken Link from Fairlead Figure 15-2 Mechanical Damage on Fairlead Link

The photographs above demonstrate both fatigue cracking and the mechanical damage with can result from the high stresses experienced by a chain link at a fairlead.

A4163-01 198

15.1.1 The Load Mechanism

The load mechanism is related to the eccentricity of thrust lines with respect to the bar neutral axis (centroid). This effect is enhanced where the change of angle is greater (for a five pocket as opposed to a seven or a nine pocket fairlead). It may also be increased where wear of the fairlead moves the contact point away from the end of the link. The imposed hogging moment is balanced by a counter effect at the other end of the link.

The chain links within the fairlead are thus subjected to an out of plane bending moment which is proportional to the tension in the mooring line. Tension variations in the mooring line result in a stress range due to both the axial and out of plane loading in the link.

Figure 15-3 - Support of a Link in a Wheel Fairlead

The fluctuating bending stress in the link is referred to as “tension bending” in API and “bending of the chain links in the fairleads” in DNV. In both cases the fatigue mechanism appears to be identical to that examined by BOMEL in their anchor chain JIP – see Section 15.1.2. Fatigue damage (SN) curves and implied stress concentration factors are broadly consistent between the three sources.

15.1.2 Tension Bending Fatigue Testing Undertaken by BOMEL

During the early 1990s BOMEL conducted a Joint Industry Project into the design of anchor chains [Ref. 10]. As part of this study work they conducted a series of tests to examine the influence of the tension bending effect on mooring line fatigue.

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Figure 15-4 - Photograph of Test Link Showing Bearing Plates [Ref. 10]

The programme included the use of a test rig representing a five pocket fairlead (see Figure 15-4 and Figure 15-5). The horizontal link was supported at four points on a mounting point which was cycled vertically in order to develop varying tension in the two fixed links. The tests were conducted on 54 mm diameter K3 chain with welded studs.

Figure 15-5 - General View of Tension Bending Test Rig (protective screens removed for clarity) [Ref. 10]

A4163-01 200

BOMEL monitored the mean and range of the imposed loads in the horizontal link and used strain gauge readings to assess the response of the chain. The result set was limited to 6 tests. The test conditions represented a different number of stress ranges.

The figure below demonstrates damage to the mounting plates during the first test. It can be seen that two of the four hardened bed plates are cracked diagonally opposite each other. The wear marks on the plates and on the links indicate that the two which cracked were more heavily loaded than the other pair. The crack in the link occurred over one of the fractured bed plates, also indicating heavier loading at this location. These wear and crack locations demonstrate the significance of “twist” or out of flatness in the unstressed link. The initial out of flatness was measured for all subsequent tests – see Figure 15-8. As can be seen in Figure 15-7 in certain cases out of flatness can be quite significant.

Figure 15-6 - Broken Hardened Plates at the end of the First Test [Ref. 10]

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Figure 15-7 - Twisted Link Due to Mis-aligned Butt Weld [Ref. 10]

When set in the fairlead the link position support restraints include bearing of the shoulders of the link against the fairlead plus of the bend at each end against the corresponding sections of adjacent links. As a result imperfection in any of the three links, or in the fairlead itself, can prevent the link from initially bearing on four shoulders.

As the link is relatively stiff BOMEL found that the load required to deform it sufficiently that load is transferred through all four bearing points may approach or even exceed the 0.2% permanent strain value.

Figure 15-8 - Simple Out of Flatness Twist Measurement Jig [Ref. 10]

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15.1.3 Conclusions Regarding Fatigue Life Calculation

Despite the limited data set, BOMEL presented a fairly consistent relationship between tension range and number of cycles to failure. Scatter appeared to be associated with initial out of flatness in certain links.

A factor on the nominal stress in the link was defined as the local (measured) stress divided by the nominal link stress.

Facnom = Factor on nominal stress = Local (Measured) stress/ Nominal link stress

Nominal link stress = LineTension/Area = LineTension /(2 x x (Bar Dia/2)2)

Nominal link stress = (2 x LineTension) / x (Bar Dia)2

The measured Facnom value associated with two point bending was 5.2. A lower Facnom

of 3.6 was measured under 4 point bending. The two point bending Facnom compares well with a value of 5.9 derived from the difference between the intercept for the fatigue performance curves for tension bending and for pure tension (all conducted in the same JIP). The stress factors for a given material can be compared using an expression of the form given below.

sionTensionTenm

AA

dingTensionBennom FacFacdingTensionBensionTensionTen )log()log(

)( 10

This expression can be re-arranged as follows for a pedagogic understanding :

msionTensionTensionTensionTennom

mdingTensionBendingTensionBennom AFacAFac

1

)(

1

)(

Where m = the slope of the TN curve.

The stress factors of 2.5 and 1.5 quoted in DNV for 7 and 9 pocket fairleads are applied to the in-plane bending stress for a link in the catenary. BOMEL record a factor of 3.7 on the nominal stress for this condition. If we use this to convert the DNV values to factors on the nominal stress we produce comparative values of 9.3 and 5.6.

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Stress factors for 7 and 9 pocket wildcats are summarised below:

DNV 7 pocket Comparative factor of 9.3 <= 2.5 x 3.7 Factor on fatigue life of 0.06 <= 2.5^(-3.00).

DNV 9 pocket Comparative factor of 5.6 <= 1.5 x 3.7 Factor on fatigue life of 0.30 <= 1.5^(-3.00).

API Effective stress factor of 1.61 <= 0.2^(-1/3.36). Comparative factor of 6.0 <= 1.61 x 3.7

API quote an upper bound fatigue life reduction factor of 0.2 which given the curve gradient of 3.36 amounts to an effective stress factor of 1.61, in this case producing a comparative factor of 6.0 on the nominal stress in the link.

Source SN Curve Factor on Nominal Stress Factor on T-T Fatigue Life

Gradient 5 Pkt 7 Pkt 9 Pkt 5 Pkt 7 Pkt 9 Pkt

BOMEL JIP 3.173 5.9 0.23

DNV OSE301 3.00 9.3 5.6 0.06 0.30

API RP2SK 3.36 9.0-6.0 0.05-0.20

Table 15-1 – Comparison between Chain Tension-Bending Fatigue ParametersNote that values in italics are derived from BOMEL measured stress factor.

Clearly both API and DNV take account of the twist / two point bearing effect and the impact that this has on fatigue at wheel fairleads. The upper bound factor from API is generally consistent with the BOMEL results for 2 point bending, with the DNV guidance appearing somewhat more onerous.

Use of the two point bending factor can be further justified by consideration of stiffness of a chain link. Even for a relatively perfect bearing geometry (0.8 mm link out of flatness on a machined support bed) approximately half of a load cycle occurs under two point bending. For a link with 3 mm out of flatness in the test rig the entire load cycle occurs under two point bending. Clearly this indicates that the higher SCF is applicable for fatigue calculations, as reflected in both DNV and API guidance.

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Figure 15-9 - Illustration of Failed Link Due to Tension Bending [Ref. 10]

Reference should also be made to Vargas et al ‘Stress concentration factors for studless mooring chain links in fairleads’, OMAE 2004-51376 which tends to demonstrate that the usual SCF’s recommended by some Rules are overestimated. In addition, DNV’s requirement for stress factors of 2.5 and 1.5 for 7 and 9 pocket fairleads is no longer present in the latest edition of OS-E301 (Oct 2004) [Ref. 5].

15.1.4 Issues Affecting Operations and Inspection

The progress of fatigue damage involves several separated phases. In the early stages the changes in the material microstructure will not be detectable. It is not until the development of actual cracking that detection becomes possible. Even then it may not be possible to detect relatively large cracks without the use of NDE techniques. Upon development of the first crack detectable under laboratory conditions BOMEL quote an average proportion of life remaining of 34 %, though the value is low as 17% in some tests. Other investigators e.g. Vicinay have reported higher values. Detecting critical crack size is obviously important for different material types. Further information can be found in Section 16 on Fracture Mechanics.

In some test cases propagation of the fatigue crack through the bar thickness did not lead to unloading of the system. It was noted that in a real fairlead, the containment offered could result in a cracked link supporting line tension. It is suggested that this could explain some reported failures occurring shortly after anchor repositioning. On this basis it could be recommended that subsequent use of fairlead chain sections in the catenary should be avoided unless detailed inspection of the chain has been undertaken. However, from a practical point of view this is unlikely to feasible.

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API makes recommendations regarding the design of the fairlead and management of the line to ensure that a link is only exposed to tension bending for a limited period of time.

15.2 Tension Bending at Chainhawse

15.2.1 Girassol Offloading Buoy Experience

This mooring system suffered a series of line failures well within the design life of the system. Subsequent engineering review of the system indicated that the principal failures were driven by fatigue damage.

The Girassol offloading buoy [Ref. 55] is a 19 m outside diameter circular buoy moored in approximately 1,320 m water depth. The original mooring system comprised 3 x 3 mooring lines. Each line was made up principally of polyester line with chain sections at upper and lower terminations. It was designed to act as a taut system with working tensions of approximately 95 Te.

Figure 15-10 - Girassol Offloading Buoy [Ref. 55]

Approximately 7 months after installation of the system one of the mooring lines failed, rapidly followed by the two remaining lines in that group. The first two failures were caused by a breakage of the fifth link from the chain stopper. The third line failed due to overload of a section of the polyester line which appears to have been damaged during installation (see Figure 15-12). The corresponding chain link on the last line was also found to have suffered fatigue damage.

Subsequent to the first three breakages, failures have occurred in both of the remaining groups of mooring lines. Clearly the system was subject to much more onerous fatigue conditions than had been considered during design.

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Figure 15-11 - Girassol Offloading Buoy – Failure in Chain Link 5 [Ref. 55]

Figure 15-12 - Girassol Offloading Buoy – Failure in Polyester Rope [Ref. 55]

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A review of the original design calculations indicated that the design had been generally consistent with the load mechanisms within the body of the chain. Repeated failures at the fifth link however indicated that an additional effect must be inducing greater fatigue loading at this location.

15.2.2 Explanation of the Failure Mechanism

It was determined that fatigue cracking of the fifth link in each mooring line was the result of a cyclic out of plane bending moment applied to that link. It should be noted that the geometry of the chain trumpet essentially restrains links 1 to 4 to move with the trumpet. Rotation between the buoy and mooring line is concentrated on link 5 and to a lesser extent on subsequent links.

Figure 15-13 - Chainhawser Arrangement and Location of Critical Link [Ref. 55]

Under low tension this rotation would be provided by slip between the links. Under higher tensions a significant inter link friction has to be overcome before this slip can occur as well as local flattening at the point of contact. These effects result in torsion in the bar at the contact point, which is represented by out of plane bending in the body of the link.

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Figure 15-14 - Out of Plane Bending Mechanism (See Section 25 – [Ref. 56]

The critical bending stress required to overcome interlink friction is proportional to the line tension and friction coefficient. For a friction coefficient of 0.1 the nominal critical bending stress amounts to approximately 40% of the nominal axial stress (total value, not range) in the chain, which is surprisingly high value. The local flattening /embedment pushes this figure higher.

40.0422

232

1.0,2

,4

2,

32

2

3

2

23

TD

DTD

TZ

AM

TDM

DA

DZ

nCalculatio

nom

nomnom

tnom

bnom

nomnomnom

Notation:

D chain bar diameter (m)

T Tension force (kN)

A Area (m2)

M Bending Moment (kN.m)

Z bar section modulus (m3)

Stress due to bending or tension (kPa)

µ Friction coefficient

nom Suffix nominal

b Suffix bending

t Suffix tension

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Notes :

i) The bending component reverses, doubling the range of extreme fibre bending stress.

ii) Stress will tend to cycle tension to tension.

iii) The above comparison is based on nominal stresses. It is anticipated that the SCF associated with interlink friction will be less than that for a link in the catenary under a tension range.

Individual links are extremely stiff. As a result very high out of plane bending moments and thus stresses can be developed, even at relatively small angular deflections. Under high tensions the interlink behaviour thus prevents links from slipping, providing a beam like behaviour in the chain sections.

15.2.3 Physical Testing Following the Girassol Failure

SBM carried out a series of tests using a rig designed to reproduce the load regime at link 5. Strain gauges were mounted on the link in order to quantify the out of plane bending stress developed. The test was carried out under both dry and in-water conditions.

Figure 15-15 - Schematic of SBM Test Rig [Ref. 55]

From their laboratory work SBM derived a relationship between interlink angle and the out of plane bending stress in the link. The measured value amounted to 288MPa change in extreme stress for an angle of 1 degree between consecutive links.

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Using this relationship with the DNV B1 curve [Ref. 57] and a limiting range in interlink angle of 3.8 degrees (imposed by geometry of chainhawse) SBM computed a life to failure of 107 days. This calculation assumed that the full pitch rotation was imposed on a single link, and that the friction coefficient was sufficient that no slip occurred up to the limiting angle of 3.8 degrees (amplitude) where the 7th link touches the chainhawse.

Figure 15-16 - Photograph of SBM’s Test Rig [Ref. 55]

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15.2.4 Relevance of the Girassol Failures to Other Systems

It can be seen from the Girassol failures that under certain conditions, the interlink friction driven fatigue can result in very rapid fatigue damage. This mechanism appears not to govern for many mooring systems, though the basic mechanics will be present for all chains.

Figure 15-17 - Typical FPSO Chain Stopper Arrangement

The requirement for rotation between the end links of the chain was not a result of the curved chainhawser. As illustrated above, where the stopper is located above the assembly pivot point, rotation of chainhawser is unlikely until the chain contacts the end of the trumpet. Small angles of rotation will thus be taken out in the first free link, either as slip or in bending.

Sensitivity to this failure mechanism appears to result from three factors in the Girassol system.

i) The nature of and natural frequencies of the moored structure resulted in angular rotations having a high frequency of occurrence at a significant magnitude.

ii) The design of the chainhawse imposed the restraint that the majority of the rotation (principally due to buoy pitch) was taken out in a single link.

iii) The relatively high working tension for the chain size permitted the development of significant interlinks friction forces and local yielding.

Stopper plates, holding a horizontal link

Pivot point of trumpet

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The relative significance of these is not yet totally clear at present. Due to the individual stiffness of chain links, large bending stresses can be developed by relatively small end rotations. These will tend to be relieved, either by slip or contact with the trumpet, for larger motions. The proportion of the rotation imposed at a single link may depend upon the chainhawse design, but this has not been studied. Friction coefficients for interlink friction combined with the line tension will determine the stress developed prior to slip, but little data is available in this area.

The simplified calculations below illustrate the accumulation of fatigue in a mooring chain. The first calculation relates to Girassol (high pre-tension and an assumed annual damage of 1.0 from the failure history). Example 2 relates to real example for a FPSO in moderate water depth and a relatively low pre-tension. Example 3 relates to an FPSO in deep water with high pretension. These calculations are intended to be indicative only, it is appreciated that the wave climate, directionality and chain hawse geometry are not represented.

In the following examples the notation listed below is applicable:

D chain bar diameter (mm)

T Tension force (tonnes)

A Area (m2)

M Bending Moment (kN.m)

Z bar section modulus (m3)

SCF Stress Concentration Factor

m Slope of the S-N curve

N Number of cycles to failure

N1 year Number of cycles in one year

Stress due to bending or tension (kPa)

µ Friction coefficient

nom Suffix nominal

b Suffix bending

t Suffix tension

A4163-01 213

Example 1 is a summary of the behaviour of the Girassol offloading buoy.

18.17.3:

318.010

)472log(173.346.11)log(

106,1,173.3,46.11)log(:

)2log(log)log(

478

22

32

2,

32

2

1.0,5.123,81

1_

))94log(173.3

778.646.11(

1

6

1

23

3

ratio

ratio

ratioyear

year

bnom

nom

nombnom

nomnom

SCFSCFNB

SCF

SCFN

NgeAnnualDamamATake

SCFmAN

MPaD

T

D

TD

Z

M

TDM

DZ

TeTmmD

Example

However, the interlink frictrion will impose a bending force on both sides of the link.

Above example developed from BOMEL JIP ([Ref. 10] Section 3.11.1, page 29).

Log10N = 11.32 – 3.173 log10( nom)

The report expression is:

Log(N) = logA –mlog(2 x SCF x bnom)

M = 3.173 is the SN curve gradient. nom is the nominal stress range in a link during

fatigue testing. This has been set to be equal to 2 x SCF x bnom. The 2 takes into account that the link can move both clockwise and anticlockwise about an axis through the line of the chain.

Within the catenary there are many chain links, increasing the likelihood of failure. The design value of logA is typically 2 standard deviations below the test mean. BOMEL took a value of 4.4 to reflect the number of chain links with a standard deviation of 0.184. BOMEL results are from tests in air. Submerged chain will fatigue more rapidly (logA increases by 0.301 based on standard fatigue texts for in air and cathodically protected in water).

In this instance Log A has been taken to be 11.46 rather than 11.32 as shown below. Considering a single link seems appropriate for the link being bent at the hawsepipe.

logA = 11.762 relates to a single link in air. logA = 11.320 relates to a 4000 link chain in air. logA = 11.461 relates to a single link in water. logA = 11.019 relates to a 4000 link chain in water.

A4163-01 214

N1 year = 6 x 106 cycles is based on a wave frequency indicative period of 5.3 seconds, i.e. (365 days x 24 hrs x 60mins x 60 sec)/5.3 seconds = 6 x 106 cycles. This is a crude approximation.

The annual damage amounts to (6 x 106 cycles)/Inv. Log(11.46 – 3.173 x log(2 x 47 x 0.318)) = 1.0002, which means the fatigue life is consumed in less than a year. This is not too different to what happened in practice on the Girassol buoy

007.0

10

)1027.3

18.1log(173.346.11)log(

106,18.1,173.3,46.11)log(:

)2log(log)log(

108

22

32

2,

32

2

1.0,60,120

2_

1

91.8

6

1

23

3

N

NgeAnnualDama

N

N

NSCFmATake

SCFmAN

MPaD

T

D

TD

Z

M

TDM

DZ

TeTmmD

Example

year

year

bnom

nom

nombnom

nomnom

Example 2 results in a fatigue life of approx 143 years

17.0

10

)2727.3

18.1log(173.346.11)log(

106,18.1,173.3,46.11)log(:

)2log(log)log(

278

22

32

2,

32

2

1.0,143,114

3_

1

54.7

6

1

23

3

N

NgeAnnualDama

N

N

NSCFmATake

SCFmAN

MPaD

T

D

TD

Z

M

TDM

DZ

TeTmmD

Example

year

year

bnom

nom

nombnom

nomnom

Example 3 results in a low fatigue life of approx. 6 years. This is potentially a significant and worrying result which merits further investigation.

A4163-01 215

15.3 Tension Bending In Wire Rope

15.3.1 Significance of Tension Bending in Fatigue of Wire Ropes

Both DNV OS-E301 and API RP2SK [Ref. 31] make reference to bending tension (B-T) fatigue of wire ropes at sheaths, pulleys and fairleads in addition to providing guidance on the calculation of tension-tension (T-T) fatigue.

API offers some indication of fatigue life reduction factors taken from experience of operations of Semi-submersibles in the North Sea. It is interesting that DNV does not provide any specific guidance on the increased rate of fatigue under tension-bending. The lack of clear guidance for calculation of this mechanism is partly due to its complexity. The objective of this section is to increase understanding of this area, rather than to provide guidance.

15.3.2 Testing at the National Engineering Laboratory (NEL)

A series of tests were carried out at the National Engineering Laboratory to examine fatigue of wire ropes under bending tension conditions in 1988 [Ref. 58]. These tests were carried out on a 40 mm diameter six strand rope with an independent wire rope core. A test rig was developed for the purpose - see Figure 15-19. The set up permitted the rope to be cycled both with respect to tension (load amplitude) and movement over the sheave (bending length) under a given mean tension.

The conclusions were as follows:

i) The rate of fatigue damage is highly dependent upon the bending length up to a travel of 25% of the lay length.

ii) The mean tension is the next most significant parameter in determining the rate of fatigue damage.

iii) The load amplitude (i.e. the range in tension) on the wire rope has relatively little influence on tension-bending fatigue.

The last item is perhaps surprising; indicating that load cycling on the rope is not the dominant source of fatigue for tension bending.

The requirement to consider a loading source other than the tension range is reinforced in OTH 91 341 [Ref. 59] where it is concluded that although the tension-tension fatigue life is driven by the load range, the bending-tension fatigue life is governed by the mean load and bending over sheave (BOS) behaviour.

A4163-01 216

15.3.3 Guidance on Damage Calculation

API give some specific guidance on the reduction in fatigue life associated with this, tabulating 3 types of wire rope at 2 bend to wire diameter ratios. Similar information can be found in table A6 of ISO 19901-7 [Ref. 4].

Wire Rope

Type

Gradient

m

D/d

Ratio

Factor on T-

T Life

Six strand 4.09 20 0.03

Six strand 4.09 70 0.08

Multi-strand 4.09 20 0.05

Multi-strand 4.09 70 0.15

Spiral strand 5.05 20 0.005

Spiral strand 5.05 70 0.015

Table 15-2 : Wire Rope Fatigue Reduction Due to Tension Bending [Ref. 31]

From the tabulated values it can be seen that the fatigue lives associated with tension-bending (T-B) are very small in comparison those for tension-tension (T-T).Unfortunately the above data makes no reference to either mean tension or bending length, the two parameters identified as critical to bending tension fatigue. The implication is that B-T fatigue can be estimated by directly factoring the calculated T-T fatigue life, which lacks consideration or either parameter. This approach could only be useful for a particular class of vessel under a specific climate.

The serious deterioration in fatigue life when bending is present has implications for Flex Boots/Bend Limiters at wire rope sockets. Evidence has been seen in the field of Flex Boots becoming detached over time. If the Flex boots become detached the wire at the socket is more likely to fail due to tension combined with bending. Figure 15-18 shows how wires which have failed due to fatigue can be recognised. Failure of Flex Boots may also result in additional torque induced fatigue at the spelter socket. This will tend to be more a factor for non torque balance IWRC rope.

A4163-01 217

Figure 15-18 – Illustration of Wire Rope Failure Modes (courtesy of Bridon)

A4163-01 218

OTH 91 341 [Ref. 59] introduces a useful distinction within B-T fatigue between an upper bound T-T life and a lower bound Bending over Sheave (BOS) value. T-T fatigue damage rates would be derived from the load range history of the mooring line and would apply to the full length of the wire rope. BOS fatigue damage rates would be developed from a combination of the mean line tension and mooring line to sheave rotations.

It is possible that the two mechanisms can be considered independently. This would depend upon the potential for bending length due to wire stretch under the tension load range. It is understood, however from OTH 91 that the BOS damage rate would be dominated by mooring line to vessel rotations, justifying independent treatment of BOS and T-T fatigue.

15.3.4 Conclusions

A large body of research has been conducted toward understanding bending tension fatigue of wire ropes. But no generally applicable quantitative guidance is offered by DNV or API on this subject.

The fatigue process and loadings associated with bending tension appears to be well understood. Substantial test work has been carried out permitting the definition of load-cycle curves for various configurations.

Therefore, the development of specific design guidance for the estimation of bending tension fatigue for offshore mooring systems appears to be feasible. It is recommended that this be incorporated into calculations for integrity of wire rope mooring systems. This is likely to become of increasing importance as the age of the wires in combination wire/chain systems increase.

Figure 15-19 - The 1.0MN Wire Rope Bending-Tension Fatigue Test Machine [Ref. 42]

A4163-01 219

15.4 General Implications of Tension Bending Fatigue for the FPS Industry

15.4.1 Implications for Design

Both API and DNV guidance includes recommendations on the design for tension bending fatigue of chain at wheel fairleads. Both sets of recommendations represent an extension to the calculations already performed for fatigue of chain within the catenary.

Depending upon the design approach used, tension bending in a wheel fairlead may be calculated directly from the catenary line tension by applying a factor on the nominal stress, or from the catenary fatigue life by applying a different factor.

Neither design code provide any guidance on the interlink friction effect associated with the Girassol buoy. It is recommended that within design of the mooring system this fatigue mechanism be considered in addition to wheel fairlead tension bending, as applicable. Note that the two effects will coexist, their relative importance governed by the relationship between line working tension and dynamic tension range.

Figure 15-20 - Tension Bending at Wheel Fairlead (Bearing Load Eccentricity) and Tension Bending from Interlink Friction (Torque at Contact)

The calculation of fatigue damage due to interlink friction at requires consideration of the chainhawse geometry and the friction coefficient. Having developed a relationship between link bending stress and motions of the unit, taking account of limiting values due to the chainhawse geometry and slip between links, a conventional fatigue analysis can be carried out. Various S-N curves have been proposed for the damage calculation. As the cracking appears to occur away from the flash weld, in a similar location to that for tension fatigue, a modified chain fatigue curve is thought to be appropriate.

A4163-01 220

15.4.2 Selection of Design Fatigue Parameters for Chain

Fatigue curve parameters proposed by DNV and API are outlined in the Table below:

Source Gradient

m

Intercept

A

Notes

BOMEL JIP 3.173 11.46 For use with single link in catenary

Adjusted for in water use

BOMEL JIP 3.173 11.02 For use with 4000 link catenary.

Adjusted for in water use

DNV OSE301 3.00 11.079 For use with catenary

API RP2SK 3.36 11.653 For use with catenary

Table 15-3 - S-N Parameters for Mooring Chain Fatigue

Note that the three guidance notes also differ in terms of the recommended safety factor on fatigue life. This factor is typically dependent on the inspection regime and may also be affected by the criticality of the adjacent mooring lines.

The BOMEL JIP contrasts mooring chain failure, where loss of any one of many similarly loaded components results in total loss of the system, to failure within a system where a degree of redundancy is present (e.g. a jacket). In order to account for the increased probability that one out of the large number of links in the mooring chain will fail a slightly more onerous curve is developed. Where a specific link (such as a link in the wheel fairlead) is considered, the single link SN curve parameters would be appropriate.

Traces of the three catenary fatigue SN curves, BOMEL catenary (BMLn), DNV studlink OSE301 (DNVs) and API RP2SK (APIc) are illustrated in

Figure 15-21.

A4163-01 221

Figure 15-21 - Comparison between Various Mooring Chain S-N Curves

Factors on stress or fatigue life proposed in the various guidance notes may be represented by factoring stress or life values, or alternatively by adjusting the intercept values to produce a case specific S-N curve.

15.4.3 In Service Inspection

In service inspection of chain sections at wheel fairleads and chainhawsers is made extremely difficult by location and poor access.

It should be noted that a visual inspection may not be sufficient to identify fatigue cracking in the chain links. Even under laboratory conditions [Ref. 10] quite large cracks could not be readily identified without the use of dye penetrant or some alternative NDE technique.

A4163-01 222

15.5 Recommendations

The constraint offered to a chain link in a wheel fairlead is such that severance of one limb of a chain link can occur without release of the mooring line. On this basis it could be argued that repositioning of fairlead chain links into the mooring catenary be avoided unless detailed inspection of the affected links has been possible. However, for normal field operations this is not a feasible process.

No guidance on the applicable friction coefficient for sliding between chain links is available. As this value is critical to the interlink friction tension bending fatigue problem, it is recommended that further work be done to identify suitable values for this.

Interlink friction tension bending fatigue and where applicable wheel fairlead tension bending fatigue should be addressed in the design of permanent mooring systems.

Bending at sheave calculations should be performed for wire rope mooring systems to identify rates of fatigue damage associated with bending-tension at the fairlead.

A4163-01 223

16 FRACTURE MECHANICS AND CRITICAL

CRACK SIZE

Experience has shown that chains and connectors are susceptible to fatigue cracking. Thus this section looks at the potential of Fracture Mechanics to help reduce the likelihood of cracks leading to complete failure.

The basis of Fracture Mechanics is that it provides quantitative answers to structural integrity questions, such as the following:

What is the critical crack size at service loads?

How safe is the system if it contains a crack?

How long might it take for a crack to grow from initial to critical size?

How often should a particular structure be non-destructively inspected?

Fracture Mechanics provides a quantitative relationship, between material, design and fabrication, or more simply between stress, flaw size and toughness. Fracture mechanics is not only a powerful tool for analytical evaluation of Non Destructive Testing (NDT) flaw indications, but is also helpful for the initial design, materials selection and any subsequent failure analysis.

In theory, a Fracture Mechanics analysis, coupled with appropriate inspection procedures, can provide a rational and quantitative method for enabling a component to be kept in service safely, at least until a scheduled inspection or maintenance outage. At this time it may be possible to undertake a repair with minimal loss of production.

Overall, therefore, it can be appreciated that Fracture Mechanics is potentially a very useful tool to assist the mooring design and integrity monitoring process.

16.1 Required Data

A fracture mechanics evaluation of a particular flaw requires accurate knowledge of the following:

1. The size and shape of the flaw,

2. The loading conditions/stress levels in the region of the flaw (Finite Element Analysis or Direct Measurement)

3. The operating environment, e.g. sea-water, splash zone, etc.

4. The fatigue/fracture mechanics properties of the material.

A4163-01 224

There are real practical difficulties in obtaining, particularly in situ, the above data for mooring lines (see Section 18). If it is not possible to detect and assess crack sizes accurately the remaining life of the component under consideration will be highly uncertain. For mooring components there can be very large variations in applied loads depending on the severity of any storms and the steepness of any waves which are experienced.

Although it is difficult at present to detect cracks in situ, inspection technology will continue to improve. Thus it is important to continue to develop our Fracture Mechanics understanding with relation to mooring components. Although good work has been done in this area – see below, it is clear that more work is still required. For example, it is important to identify the maximum defect size that can be permitted during manufacturing, while still allowing a satisfactory mooring component field life.

16.2 Fracture Mechanics and Chains – State of the Art Summary

A number of groups have been using Fracture Mechanics as a tool to understand and to analyze fatigue induced crack growth of mooring chains in dry air and in hostile environments. These include Vicinay Cadenas, Labein, Agder College of Engineering, Grimstad, and the Department of Metallurgical Engineering and Materials Science of the Bilbao Engineering Faculty (UPV-EHU).

To reveal fatigue crack behaviour in mooring chains, measurements were carried out for high strength steel (Grade R4) in the Labein Laboratory, Spain, using Compact Tension (CT) specimens with 12.7 mm thickness. These tests were performed in 1999 and 2000 in accordance with standard ASTM E 647 procedures. The specimens were tested in air and in sea water with a frequency of 1 Hz. The fatigue crack growth was monitored by an Alternating Current Potential Drop (ACPD) method and the crack growth rates were plotted as a function of the Stress Intensity Factor Range (SIFR).

In 2003 a second series of tests using specimens of steel grade R4 were undertaken at Agder University College, Norway. In this case Compact Tension (CT) specimens with 25 mm thickness were tested in various environments under constant amplitude loading. The fatigue crack growth was monitored by an Alternating Current Potential Drop (ACPD) method and the crack growth rates were plotted as a function of the Stress Intensity Factor Range (SIFR). The tests were carried out in dry air, in sea-water without protection against corrosion and in sea-water with cathodic protection. The cathodic potential was set to 890 mV and 1100 mV relative to an Ag/AgCl reference cell.

A4163-01 225

The measured growth rates were compared with the rates for medium strength carbon manganese steels as found in standard codes e.g. BS7910. The measured growth rates were well within the scatter band given for these steels freely corroding in air. The crack growth rates found in seawater with cathodic protection were, however, substantially lower than the rates given in BS7910. When a cathodic potential of -1100

mV was applied, crack closure was observed at medium levels of K. The explanation is the formation of calcareous deposit in the wake of the crack front that gives significantly reduced growth rates and finally leads to crack closure. This finding is a surprise for high strength steel. The results are promising and should be investigated further including the implications for the offshore operation of cathodic protection systems.

A linear elastic fracture mechanics model was established to study the fatigue behaviour in a studless link. The recorded growth parameters were used in conjunction with a crack-like initial flaw with depth in the range from 0.12 to 0.25 mm. The difference found between the growth rates in dry air and in free corrosion were in accordance with tested fatigue lives for these two environments.

In general, after chains have been broken during fatigue testing microscopic observations have been undertaken of the fatigue fracture surfaces to confirm the crack growth process and any initial defect. In this way it has been possible to adjust the validity of the fatigue model parameters.

16.3 Fracture Mechanics Critical Crack Size Implications

Knowing the critical crack size which could lead to rapid chain failure is important for chain inspection. Additional research is need in this area to identify what are the critical crack sizes. This will be an important input in helping to develop new technology capable of detecting these sizes of cracks before they propagate through the material thickness.

A4163-01 226

17 LINE STATUS MONITORING AND FAILURE

DETECTION

17.1 Instrumentation Status - Survey Results

Given the safety critical nature of mooring lines one might imagine that they would be heavily instrumented with automatic alarms which would go off in case of line failure. In practice many FPSs are not provided with such instrumentation/alarms – see the indicative statistics below. On type a) turrets, in which the chains are permanently locked off under the hull, it is particularly difficult to monitor these lines in a reliable manner. For example, how do you readily distinguish between mooring line and instrumentation failure, without direct intervention?

Another factor which makes it difficult to be 100% sure of the condition of a set of mooring lines is that line breaks do occur along the sea-bed or in the thrash zone. If this happens the line will drag through the mud until the friction exerted by the soil surrounding the chain matches the tension in the chain at its sea bed touchdown point. Anchor handling experience and calculations has shown that very high line pulls are required to drag large diameter chain through the sea-bed.

The following indicative statistics, based on data from the majority of North Sea based FPSOs, give an indication that instrumentation is not as prevalent as might be expected for such a heavily regulated region:

50% of units cannot monitor line tensions in real time.

33% of units cannot measure offsets from the no-load equilibrium position.

78% of units do not have line failure alarms.

67% of units do not have mooring line spares available.

50% of units cannot adjust line lengths.

If the level of instrumentation/alarms in the North Sea is patchy, it seems likely that units operating in less heavily regulated regions will have even less instrumentation.

A4163-01 227

17.2 Existing Failure Detection Systems

17.2.1 Simple Sonar Probe

This system is illustrated in Figure 17-1 and Figure 17-2 and is employed on a North Sea FSU. The Sonar head is deployed through the centre of the chain table to approximately 15-20 metres below the hull. The head is deployed every 2 weeks in calm weather or after a storm to confirm that all the mooring lines are present.

Figure 17-1 - Sonar Fish for Deployment through Turret (courtesy Chevron Texaco)

Figure 17-2 – Sonar Fish Deployment Method (courtesy Chevron Texaco)

A4163-01 228

The illustrated system is fairly simple and is easy to repair if something does go wrong with it. Figure 17-3 illustrates the image which can be seen on the sonar display screen, namely 12 mooring lines and two risers close in to the centre. However, the system does have two important limitations, namely:

1. If a line breaks in the mud (not unknown) it will still have some tension/catenary and thus the change in the screen appearance may not be sufficient to indicate that a line has failed.

2. A line could fail and not be detected for 2 weeks, during which time a severe storm could develop.

Figure 17-3 - Sonar Display Screen Showing 12 Mooring Lines and 2 Risers Close to the Centre (courtesty Chevron Texaco)

17.2.2 Use of Micro – ROVs

The possibility of a line failing in the mud and not being detected is a realistic concern. For example one FPSO has experienced a break in the mud line approximately 8 years into its field life. If, however, FPSs were equipped on installation with the type of simple inclinometer shown on Figure 17-4 it would be possible to determine, in calm weather if any of the mooring line angles have changed to a significant extent. The inclinometers could be checked using a “Football” sized ROVs which can be deployed directly from the deck of the FPS itself. This removes the need for expensive ROV intervention vessels – see Section 0. These small ROVs can be stored on the FPS itself or can be sent out by a helicopter as the need arises. Simple inclinometers overcome the difficulties sometimes encountered with damage to power and signal distribution cables on more complex systems. Being able to do a “fly by” in good weather to read all the inclinometers would show whether the mooring line tensions are still in balance, or if for slack or “dog legs” have been pulled out of the system – see Section 6.2.1.

A4163-01 229

Figure 17-4 - Simple Pre-Installed Inclinometer with + or – 1 Degree Accuracy (Courtesy of Shell/SBM)

Figure 17-5 - Illustration of a “Football” Sized ROV (Courtesy of I. Williams)

A4163-01 230

17.2.3 Instrumented Mooring Lines

Intrinsically the simplest way to finds out if a mooring line has failed is to include a load cell in the line, ideally close to the fairlead, where the tensions are normally highest. Such a system is illustrated in Figure 17-6. Figure 17-7 shows the very useful data which can be obtained from such a system as long as it is working properly. However, particularly for submerged turrets, because the mooring lines are not readily accessible, if the sensor in or the wiring/connections fail, you are in the difficult situation of not knowing whether the line has failed or the sensor has failed. If you record all line tensions and a line fails you should see tension pulses on the adjacent lines. These should be detectable if the recording interval is frequent enough and the load cells are sufficiently sensitive, although this does mean that you end up accumulating a lot of data. On one instrumented North Sea FPSO a mooring line failed, but it took two weeks of data processing from the other lines to reveal the tension spike that confirmed it was a real failure rather than an instrumentation fault.

Figure 17-6 - Instrumented Load Pin – Shackle Link (courtesy of BMT/SMS)

The power and signal transmission cables are areas of particular weakness for systems exposed to long term offshore loading conditions. They may not even survive the installation operation. To quote from one project,

“The load monitoring systems are not commissioned yet. The load cell cables did not last the tow from the conversion yard as they all came off their cable trays running up the side shell and were damaged - site did not use the specified number and size of cable ties. All cables still to be replaced.”

Power & data transmission

cable

A4163-01 231

This quote shows the low priority which is typically assigned to mooring line instrucmentation.

Figure 17-7 - Indication of the Data Available from Instrumented Mooring Lines (courtesy of BMT/SMS)

Theoretically you could go for a simpler system, for example using limit switches placed on the trumpet assemblies. However, without moving the trumpet assemblies it is not clear how these could be tested in situ to confirm whether or not they are still functioning. Moving the trumpet assemblies with the chains in situ is not feasible without the use of powerful anchor handling tugs.

External Turret or Spread Moored – Moorings Lines Visible

For FPSOs with internal turrets or spread moored units, where the chains come up onto the deck, it is relatively easy to confirm that the mooring lines are still present by simple visual observation. Again, however, there can be a difficulty if a mooring line fails in the mud. For lines which cannot be seen clearly from the FPSO deck regular checks should be made, for example by supply or standby vessels that all the lines are present. This should be written into the standard operating procedures.

A4163-01 232

17.2.4 FPS Offset Monitoring and Line Failure Detection

If a mooring line fails the resulting equilibrium position would change and theoretically it should be possible to detect this based on offset monitoring. However, apart from in deep water, if a mooring line fails in moderate weather conditions it is difficult to distinguish the change in offset from the normal offset changes due to wind, wave and current effects. Perhaps surprisingly mooring lines do fail quite often in moderate conditions, sometimes following on from storm loading.

In addition, the direction from which the weather comes from may influence the effectiveness of offset monitoring for line failure detection. For example if a line fails and the weather pushes the unit in the direction of the failed line, the offset from the equilibrium position will be small compared to the weather pushing the unit in the opposite direction to the failed line.

Satellite drift and possible gyro malfunction can affect the accuracy of offset monitoring. For example a system is installed on one North Sea unit and this has indicated out of position alarms when there were no line failures. This can be due to a poor Global Positioning System (GPS) fix depending on the number of satellites available at a particular time. In another incident the FPSO’s gyro became unstable and this resulted in high apparent offsets. However, as long as false alarms do not happen so often that they are automatically discounted, the odd false alarm helps to keep people thinking about moorings. In addition, it was helpful that the gyro problem was noticed early on before it could have had an impact during say an offloading operation.

Overall offset monitoring and recording is cheap and worth having since it is surprising what mariners can deduce from experience and relatively little data. For example, if you are used to the FPSO taking up a certain offset in moderate south westerly conditions and this, plus the overall response of the vessel seems to change, would be a good trigger to deploy a micro-ROV to check out the condition of the lines – see Section 17.2.2.

It should also be noted that offset monitoring is a potential input to other possible line failure detection techniques, see for example Section 17.3.1.

17.3 Future Failure Detection Systems

New methodologies to detect a mooring line failure typically feature scanning acoustic transponders deployed through the turret, attached to the hull of the FPSO (see Figure 17-8 and Figure 17-9), or installed on the seabed to provide an indication of the catenary’s profile. The advantage of these compared to the simple dipping sonar described in Section 17.2.1 is that, in calm conditions, it is hoped that they should be able to detect the change in catenary profile which is likely to be associated with a line break in the mud. Two different systems based on this basic approach should be tested in the near future in the North Sea.

A4163-01 233

Figure 17-8 - Illustration of a New Sonar System due to be Installed in the North Seas (courtesy of I. Williams)

It will be interesting to see if this system proves to have sufficient resolution in practice to pick up a line failure in the mud – see Section 17.2.1.

Figure 17-9 - Close Up of the Proposed Sonar Head (courtesy of Ian Williams)

A4163-01 234

17.3.1 Response Learning System (RLS) for Automatic Line Failure Detection

Another line failure detection option may be a Response Learning System (RLS) which takes into account the expected performance in measured weather conditions. The response will be different if a line fails due to a resulting change in the mooring system stiffness. If a unit is equipped with an environmental detection and recording system and a DGPS (Differential Global Positioning System) location system it should be possible to utilise learning algorithms, similar to those used by Dynamic Positioning (DP) systems, to evaluate, for a given applied environment, what the excursions should be for an intact and one line failed condition. Figure 17-10 includes a flow chart which illustrates this process. Hence, if the excursions do not match the predictions then an automatic alarm should be sounded, alerting the crew that a line may have failed. Overall this is a fairly complicated procedure and will require investment to develop further. However, it has the real benefit that it would be a relatively simple retrofit to existing installations, avoiding the need for expensive intervention work such as installing load cells and wiring. Also if the system breaks down it should be possible to fix it without any “wet” intervention.

Vessel/ Mooring

mathematical

model

Predicted

Vessel

Position &

heading

Difference

between

predicted &

actual

Vessel response

to environment

Measured

Position &

Heading

Revise

mathematical

model

coefficients

Predicted

Tidal Current

& direction

Draft Sensor

Measured

Wind Direction

& Magnitude

Vessel/ Mooring

mathematical

model

Predicted

Vessel

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Figure 17-10 - Response Learning Without Line Tension Input

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17.3.2 Utilization of Riser Monitoring Technology

Converting Motion Data into Line Tensions

The subsea motion sensors can monitor six degrees of freedom motion. However, what is really wanted from a mooring perspective is real time mooring line tensions. This is more complicated, but is believed to be achievable.

It is suggested that the following approach could be utilized to evaluate real time line tensions. The advantage of this approach, relative to strain gauges, is that no major intervention is required to install load cells as part of the mooring line.

1) Install, at a suitable in air locations on the FPS a motion reference unit (MRU) and data logger.

2) Based on the data from this MRU the real time motion at each of the fairleads can be determined and recorded.

3) Input the motion time trace into a high quality line dynamics mooring analyses programme to evaluate line tensions.

Although the previous approach will give an estimate of the line tensions the accuracy will depend on whether the drag and damping evaluated by the line dynamics programme is reasonably correct. Hence a further refinement recommended to cross check the line tensions results. This cross check would comprise the following:

1) Strap on a motion sensor to a mooring line at a known distance from the fairlead, say 30m.

2) Collect motions data for this point on the mooring line while also recording at the mooring line while also recording at the same time data on fairlead motion.

3) Compare the predicted motion at 30m down the mooring line with the actual behaviour.

4) If there is a significant difference modify the drag and damping parameters in the line dynamics programme until convergence is achieved.

What is interesting about this approach is that it provides a means to identify the maximum tension in a mooring throughout its length. This is because, depending on dynamic behaviour, the maximum line tension may not be at the top of a mooring line.

Remote sensing technology has been utilized to monitor the behaviour of flexible risers – see Figure 17-11. These sensors tend to be battery powered and low power. The signal from the sensor can be acoustically transmitted to a data logger on the platform without the need for wires. On risers the sensors have been changed out by a ROV when their in-built batteries become exhausted after several months.

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Figure 17-11 - Illustration of Riser Monitoring Instrumentation (courtesy of 2H)

Real Time Monitoring of Line Tensions

Real time mooring monitoring provides an option to resolve the uncertainty which always exists as to whether real behaviour is close to the initial predictions. This has the following benefits:

A check can be made on storm loadings.

Fatigue life predictions can be updated.

IMR strategies can be modified as required.

The required sensors for mooring monitoring are basically low power. Hence there may be some option to power sensors from the fluctuations in mooring line tensions and transmit the signal acoustically to a transponder mounted on the FPS hull.

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17.3.3 UK HSE Position on Failure Detection

The present position of the UK Health and Safety Executive (HSE) on failure detection is that Operators should have in place suitable performance standards for the time taken to detect a mooring line failure. This is particularly important as common mode failure mechanisms, such as fatigue or wear, are likely to be prevalent on more than one mooring line and early detection of a line failure with appropriate mitigation strategies could prevent system failure. Depending on the inherent redundancy of the mooring spread, the time taken to detect a failure could range from virtually instantaneous detection to detection in a matter of days. It is clearly not appropriate to rely on annual ROV inspection to check if a mooring line has failed. Monitoring the excursion of a FPS, particularly using differential GPS is inexpensive and will provide mariners with a feel for the mooring integrity. But without real time monitoring of the environment it is unlikely to indicate a line failure in anything but storm conditions, unless in deep water – see section 17.2.4. Satellite drift is also a potential factor affecting the reliability of offset monitoring.

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18 INSPECTION, REPAIR & MAINTENANCE (IRM)

18.1 In Air-Inspection

Mobile Offshore Drilling Units (MODUs) need to recover their mooring lines and anchors on a regular basis when they move from one location to another. This provides periodic opportunities to undertake in-air mooring line inspection when the vessel is in sheltered water. Alternatively a spare line may be bought or rented, which can be swapped out with one of the existing lines while the original line is taken to the shore for inspection and possible refurbishment.

FPSs spend much longer on location than MODUs. Hence, their mooring lines are normally only recovered when the FPS moves off location. It is possible to recover mooring lines part way through a field life, but this has two disadvantages, namely:

1. The lines may be damaged either during recovery or re-installation 2. The whole operation is expensive since the services of anchor handling and

possibly heading control tugs will be required for a number of days.

Given that even in-air inspection will not necessarily detect all possible cracks and defects which may be present, there is an understandable interest among Operators to undertake in-water inspection. However, there will still be times when anomalies are identified which can only be resolved with true confidence by undertaking in-air inspection. One definite advantage of in water inspection is that it is easy to identify which parts of the chain have been in the thrash zone and at the fairlead. This is more difficult to determine for long lengths of chain lying on a quayside.

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18.2 Where to Inspect on a Mooring Line

Figure 18-1 illustrates the areas on mooring line which are subject to the highest degradation and should be most closely inspected. In particular, in field experience suggests that the less loaded Leeside lines (see Figure 1-1 and Figure 3-4), which see more relative rotation and motion, are subject to the greatest amount of wear.

The length of mooring line which seems maximum wear on the sea-bed is quite localised. Hence it is important to ensure that the ROV measures the right links on the sea-bed section. On Figure 7-9 the blue dotted vertical line shows the location of the no applied load touch down point. It is interesting to see that the blue line is approximately at the bottom of the black poly line which is a curve fit through all the line 7 diameter measurements. In other words the maximum wear has occurred at this point.

XY

Z50 m

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Orc aFlex at 08:30 on 05/04/02: Block 5_Multip le_Static s_Adjus ted_Load_4_5_6_U ni_Sets_Steep_Sea_MPM_Exc ur_Laden.dat (az imuth=280; elevation=5) Static s Com

Figure 18-1 - Red Arrows and Black Line Indicate Key Areas subject to Degradation on a Mooring System (leeward likely to have worst wear)

In Figure 18-2 where there is a red arrow there will be weight per metre discontinuity as you change from wire to chain. Where there is a weight per metre discontinuity one may experience increased relative rotation and thus wear. This seems to be particularly pronounced on leeside lines.

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Figure 18-2 - Example of a Weight Discontinuity which may Result In Enhanced Wear

18.2.1 The Problem of Inspection when you cannot Adjust Line Lengths

For the majority of FPSOs (i.e. non Tentech designs) which have the lines stoppered off at the base of the turret, adjusting line lengths is only possible as part of a major operation with a dive support vessel present (DSV). Line adjustment is not intended to be undertaken during annual or bi-annual inspection operations.

Not being able to adjust line lengths presents a real issue with regard to access for line inspection operations. As has been seen from the Section 9.2.2 case study it is very difficult to see what is happening inside or even at the outer edge of the trumpet or hawsepipe. If it is possible to drop the line tension, so that the links which have either been held in a chain stopper or otherwise been working in the pocket of a gypsy wheel are accessible, this makes inspection much more straight forward. To fully inspect the touch down point and thrash zone it is desirable to lift the chain off the sea-bed. The simplest and safest way to do this would be to pull in on a winch in the turret. If this is not possible, due to the FPSO design, theoretically it might be possible to grapple for the chain using a “J” hook from anchor handler. However, this might damage subsea infrastructure and may not be permitted. What this means in practice is that the static touch down point and thrash zone, which for the static equilibrium position extends both up the catenary towards the FPSO and along the sea bed section towards the anchor, is difficult to inspect. In other words on many FPSs a section of mooring line subject to some of the worst degradation is difficult to inspect properly.

In certain cases it may be possible to operate thrusters to pick up some of the sea bed chain or even to utilise a tug to pull a FPSO away from its normal equilibrium position. This will need to be risk assessed on a case by case basis. If a tug is used to move an FPSO it is vital that all components are strong enough to take the applied loads including any closed chock fairleads on the FPSO. There has been one incident of a closed chock fairlead failing while load was being applied by a tug.

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18.2.2 Inspection Access to the Stoppers

In general, all the links in the trumpet area are difficult to inspect. Hence, if a link is going to be exposed to 20 years of dynamic motion, does it make sense to place it somewhere where it cannot be inspected, even if you have a high fatigue safety factor.

Figure 9-12 and Figure 9-13 show the level of wear noted on a mooring line which was recovered back to shore after six years of deployment in the North Sea. At the turret interface there are bending and twisting stress raisers, plus non perfect link geometry, which make the situation worse compared to a pure tension-tension situation.

There are different designs of internal turrets and some may appear to give more ready access to the chain stoppers than others. However, even for the type of turret illustrated in Figure 18-3 and Figure 18-4, the room at the base of the structure is flooded. Thus for example the picture in Figure 18-4 was taken by a camera mounted on a pole.

Figure 18-3 - Typical Turret Cross Section Illustrating that the key Mooring Components are Submerged

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Figure 18-4 - Chain Stopper View Prior to Chain Installation with Pull in Rigging Present (compare to Figure 18-3)

It is important, for future designs how to improve accessibility for inspection. This has implications for mooring design brief or specification – see Section 20.

18.3 In-Water Inspection

To date chain mooring components have been the subject of the greatest effort to develop in-water inspection methods. This is because they are typically used in the sections of moorings subject to the greatest deteriorative forces, particularly at the seabed touchdown (thrash zone) and at the vessel interface. Both windward and leeward lines should be inspected, but a particular check for wear should be undertaken on the leeward lines, see Figure 3-4. Care is needed when inspecting the touchdown zone, since potential hazards such as rocks or debris on the sea-bed can cause mooring line abrasion. These hazards may be partially obscured by the sea bed/mooring line and thus good visibility with powerful lighting is required.

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18.3.1 In-Water Chain Measurement

A number of in water mooring chain measurement systems have been developed with varying success, ranging from simple diver-deployed manual callipers to a prototype stand-alone robotic system and ROV deployed systems.

Diver inspections are, in general, not a favoured option. Mooring chains are highly dynamic and therefore are potentially dangerous when divers are in close proximity. Also diver inspection has been proven to generate inconsistent results and has inherent depth limitations, for example, when checking the thrash zone.

A stand-alone robotic system has been developed, but to date this seems to have been too large and cumbersome for practical offshore operations. In addition, it does not appear able to inspect the vital seabed touchdown or get in close to the fairleads.

Possible ROV-deployed systems include both mechanical calliper and ‘optical calliper’ systems. Mechanical callipers have met with limited success, primarily because during deployment onto chain they have the potential to be knocked out of ‘true’ and consequently may well have to be recalibrated between successive measurements.

The most established ROV-deployable chain measurement system is effectively an ‘optical calliper’ developed by Welaptega Marine Ltd. It comprises of multiple high resolution video cameras and lights on deployment frame, which is equipped with scale bars in pre-assigned orientations and at set distances from each other and the cameras (Figure 18-5). The system measures the chain parameters by calibrating from the tool scale bars and resolving dimensions and optical distortions using offline image analysis software.

This type of system has no depth limitation, requires no physical recalibration and can be configured to measure not only chain components at the seabed, but also in difficult to access regions such as the vessel interface. It can also be configured to measure other types of mooring ‘jewellery’ such as connectors, shackles and kenter links.

The ‘optical calliper’ chain measurement technology is used extensively by offshore operators and is accepted by a number of offshore certification authorities. In this respect, in at least one instance, it has been used as the basis for an extension of the prescribed recertification period for an in-service FPS facility.

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Figure 18-5 - Illustration of ROV Deployed ‘Optical Calliper’ Measurement System(courtesy of Welaptega Marine Ltd)

18.3.2 Loose Chain Stud Detection

As discussed in section 3.2.3 in studded chain, loose studs have been implicated in crack propagation and fatigue. Accordingly studded chain inspection and re-certification protocols require the assessment of the numbers of loose studs and degree of ‘looseness.’ However, there is no consensual industry opinion with respect to loose stud reject criteria. Traditionally chains have had to be recovered for detailed loose stud determinations and have relied on a manual test, either moving the stud by hand or using a hammer to hit the studs. The resulting resonance (a ‘ping’ or ‘thud’) is used to assess whether a stud is loose or not.

Recently Welaptega Marine Ltd has developed an ROV-deployable loose stud detection system. The system uses an electronically activated hammer to impact the stud and uses a hydrophone and a micro-accelerometer as sensors. A software program is used to distinguish between ‘loose’ and ‘tight’ responses. Cross checks can be carried out in that very loose studs can be detected using a ROV manipulator or a ROV deployed high pressure water jet.

Camera block

Underwater light

Deployment guide

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18.3.3 Component Condition Assessment

As well as chain dimension checking it is also important to assess link integrity and condition. The overall, or general, condition of mooring components often gives insights into the types of deteriorative processes that are at play. For example surface pitting may be indicative of pitting corrosion, ‘scalloping’ or indentations of wear, fretting corrosion, or ‘anvil’ flattening, and unusual geometry may indicate friction bending, or plastic deformation (e.g. stretch).

Underwater visual condition assessment by ROV is particularly difficult because of the inherent ‘flatness’ of video images from standard 2D inspection cameras. With 2D cameras it is very difficult to distinguish whether a visual artefact on a surface is merely a mark, or a region from which material has been lost (e.g. a pit).

The shortcomings of 2D video can be addressed by using 3D visualization, a long-time goal in the underwater inspection sector. Over the last two decades a number of 3D visualization systems have been implemented but, until recently, with limited success due to problems with user comfort and impractical and cumbersome viewing systems.

Advances in 3D camera design and the development of user-friendly viewing systems have led to the introduction of a new generation of 3D video systems [Ref. 60]. These cameras come in a range of configurations, sizes and depth ranges and have proven very effective for the assessment of the surface condition and general geometry of mooring components. Improvements have also been made in video asset management, so that it is now easier to access data without trawling through hours and hours of video footage.

As part of any in-water inspection it would be prudent to identify and inspect all kenters and D shackles to confirm that they appear to be intact and that all split pins are present.

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18.4 Marine Growth Removal

A key challenge of conducting in-water inspection is getting access to the component(s) to be inspected. Materials which have been in sea water for extended periods accumulate varying levels of marine growth which can be heavy, depending on geography, water depth and season (see Figure 18-6). This growth needs to be removed so that the underlying mooring components can be inspected.

Figure 18-6 – Illustration of Heavy Marine Growth on Long Term Deployed Chain

Cleaning options include manual brushing by divers, rotary brushing with wire or synthetic fibre brushes and ROV deployed high-pressure water or grit-entrained high pressure water. Each system has its own pros and cons.

Once marine growth is removed it is possible to conduct various levels of inspection including general visual inspection (GUI), dimensional measurement and assessment of mechanical fitness. Unfortunately cleaning off marine growth and scaling by high pressure water jetting may accelerate corrosion by exposing fresh steel to the corrosive effects of salt water. At present there are currently no in-water inspection methods for mooring components that do not require the prior removal of marine growth. This represents a technology gap, which warrants further investigation.

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The time required to remove marine growth depends largely on the cleaning option chosen and in light of the cost of ROV vessels, can be a substantial component of the cost of an inspection program. Consequently it is essential that the planning stage of mooring inspection campaigns should consider the most suitable cleaning options for the expected conditions.

18.5 Manufacturing Tolerances and the Inspection Implications

From an inspection point of view it is extremely important to have a good idea of what the dimensions were of a mooring component when manufactured. Thus, the significance of any changes in component dimensions over time can be assessed correctly. With forged components, such as chains and shackles, there will tend to be an inevitable variation in dimensions. Section 3.2.7 provides indicative chain manufacturing tolerances. Therefore, for key areas, such as at the turret interface, it is important to obtain key bench mark measurement data during the original installation process. At the present time this does not normally happen.

18.6 Wildcat/Gypsywheel Inspection

In general, whenever in water mooring line inspection is undertaken, a check should be made of the condition of the wildcat pockets. The chain must be pulled in or let out to expose the wildcat pockets which are hidden at a given chain position / fairlead orientation. It has been found on semi-submersibles that if the pockets are damaged badly worn this typically leads to accelerated chain wear and damage – see Figure 18-7, Figure 18-8 and Figure 18-9.

At the gypsy wheel the key links are those that make regular contact with the pockets on the gypsy wheel. These should be clear of marine growth and thus fairly easy to identify once the line is slackened off. If this is not the case it would be good to mark one of the links before the line is slackened off. If this is difficult to achieve the line should be slackened off a precise number of links so that one knows which links were on the gypsy wheel. Taking some still photographs before the chain is slackened off is a wise precaution. It is desirable to take sufficient measurements at the top of the catenary such that one can compare the wear on links on and close to the gypsy wheel with those further down the catenary.

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Figure 18-7 - In-Situ Inspection of a Wildcat Pocket by Abseillers(Courtesy of CNR)

Figure 18-8 - Close Up Of Fairlead Pocket – Note Slight Lip on the Right(Courtesy of CNR)

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Figure 18-9 - Example of Chain Wear From Sitting in a Wildcat Pocket(Courtesy of CNR)

Figure 18-10 - Red Zones Highlight the Importance of Checking all Relevant StructuralConnections (Courtesy of CNR)

The structural connections between the wildcat fairlead assembly and the hull structure (see Figure 18-10) should also be regularly checked. Problems have been known to develop in this area [Ref. 61].

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Figure 18-11 shows damage to a submerged wildcat or fairlead lubrication line as noted during an abseiller based inspection operation. Although not all wildcats require lubrication, if a system is designed to have lubrication it can be seen that it is fairly easy for, even steel, lines which go through the splash zone to become damaged. This illustrates the difficulty experienced running power and signal transmission lines through the splash zone – see Section 17.2.3. If the wildcats are designed for lubrication and are without it for an extended period the chances of seizure are inevitably increased – see Section 8.

Figure 18-11 - Example of a Parted Lubrication Line Feeding a Submerged Wildcat or Gypsy Wheel (Courtesy of CNR)

18.6.1 Flatness of Chain Links and Torsion Implications

If a link which sits in a wildcat pocket or chain stopper is not flat (see for example Figure 15-6, Figure 15-7 and Figure 18-12) it will be subject to regular bending stresses. Over time this will have an impact on the fatigue life of the supported link (see section 15.1.3).

Unfortunately, which a FPS goes on station, it is impossible to know in advance which link will be sitting in a chain stopper or wildcat. Therefore, it is desirable to check the flatness of all the links at the end of the chain which may be held/constrained. Figure 15-8 illustrates a simple gauge which can be used to check whether links are flat.

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Figure 18-12 - Example of a Non Flat Link

18.6.2 In Situ Inspection of Wire Rope

Wire rope is particularly difficult to inspect and, at the present time, tends to be somewhat subjective, see Figure 10-1 and Figure 11-6. Sheathed spiral strand wire is even more difficult to inspect, since it is obscured by the sheathing. However it is difficult to assess if the sheathing becomes damaged during installation, for example going over the stern roller. If the sheathing is damaged letting in sea-water, this could result, over time, in accelerated undetected corrosion. Also abrasion could occur on the seabed and this would be difficult to determine.

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A previous JIP (Subsea Electro-magnetic Appraisal of Wire Mooring Lines (SEAL) [Ref. 62] was intended to develop a ROV deployed in water wire rope inspection tool. However, this JIP only went as far as Phase I – Design. The proposed subsequent two phases, which did not attract sufficient funding, were:

Phase 2 – construction of a prototype and completion of onshore trials.

Phase 3 – offshore proving trials.

An in air based wire rope inspection unit which was tested on ther Buchan FPS wire ropes is illustrated in Figure 18-13. Figure 18-14 shows a sketch of the proposed SEAL tool deployed on an inclined mooring line from an ROV. Given the difficulties involved in inspecting wire rope and the age of some of the wires presently in use, it is recommended that consideration should be given to moving forward with Phases 2 and 3 of SEAL.

Figure 18-13 - Buchan FPS Wire Rope NDT Inspection Head

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Figure 18-14 - Proposed Wire Rope Inspection Toll Delpoyed from a ROV

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18.6.3 Acoustic Emissions

Acoustic emissions are short bursts of elastic energy released as stress waves resulting from irreversible deformations in the material under test. Very small changes in conditions at any point in a material normally produce a large number of emissions. In theory these emissions can thus be used to detect, locate and characterise defects. A prototype acoustic emission system was developed at Cardiff University but never got to the stage of being sold on a commercial basis. A more update review of acoustic emissions can be found in HSE Research Report 328 (2005) [Ref. 63]. The system relied heavily upon instrument software and a very powerful post-processing and analysis package [Ref. 64].

18.6.4 Cathodic Potential Checks (Impressed Current & Sacrificial Anode Systems)

For mooring systems which are designed to have corrosion protection via impressed current or sacrificial anode systems it is important to check whether the system is operational. For example, on one FPSO the earthing cables to provide electrical continuity between the FPSO hull and mooring chanins were never installed.

The status of the system can be checked by undertaking a Cathodic Potential (CP) survey. NACE Standard [Ref. 71] states that using a silver/silver chloride reference electrode readings between -800mV to -1,100mV suggests adequate protection. Further information can also be found in European Standard EN 13173 “Cathodic Protection for Steel Offshore Floating Structures” [Ref. 72]. Reference should also be made to section 16.2 where the interesting observation is made that at a cathodic potential of -1,000mV crack closure was observed due to the formation of calcareous deposits in the wake of the crack front.

Lloyds Rules and Regulations for the Classification of a Floating Offshore Installation at a Fixed Location (May 1999, part 8, ch 2.1.3, section 1.2.4) states a more negative value may be used for those locations where sulphate reducing bacteria may be active. Where higher cathodic protections are applied it is necessary to watch out for hydrogen induced embrittlement – see sections 7.3 and 7.4.

18.6.5 Checking Mooring Line Pre-Tensions

The importance of a balanced mooring sysem in terms of pre-tension values is discussed in detail in section 8.1.

With a ROV in the field it is possible to check the absolute accuracy of the mooring line tensions. This can be done in two ways:

1. Measure the x, y and z co-ordinates of the mooring line touch down point. This will be difficult to do precisely if the FPV is moving around much.

2. Use a ROV to temporarily mount an inclinometer on the chain close to the fairlead.

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18.7 Inspection Frequency – Code Requirements

Annual Surveys would typically be carried out by Classification Societies on mobile offshore drilling units (MODUs) comprising visual inspection of the accessible chain links on or adjacent to the windlass. Intermediate Surveys are then normally performed at the second or third surveys following on from a 5 year special survey. The intermediate surveys would normally be undertaken at a rig move and would include 100% visual inspection of all the chain, excluding that which remains in the chain locker during normal operations.

Since FPS’s are not subject to rig moves, intermediate survey chain inspections are difficult/costly. Hence FPSs which are classed tend to concentrate on the 5 yearly special periodic surveys. However, the fact that annual and intermediate surveys are felt necessary for drilling semis shows that there is a need for regular inspection.

Lloyds Rules and Regulations for the Classification of a Floating Offshore Installation at a Fixed Location, (May 1999) state the following:

“2.2.10 For positional mooring systems a rota of component parts of the mooring system is to be examined at each Annual Survey. A periodic inspection programme is to be developed by the Owners/operators and submitted to LR’s Headquarters for approval. Annual Surveys should be capable of determining as far as practicable the general condition of the mooring system including cables, chains, fittings, fairleads, connections and equipment. The Surveyor is to be satisfied that all components and equipment remain in an acceptable condition. Particular attention is to be paid to the following:

Cable or chain in contact with fairleads, etc.

Cable or chain in way of winches and chain stoppers

Cable or chain in way of the splash zone.”

It is interesting that no mention is typically made of the initial requirements for calibration of tension meters, nor how often they should be recalibrated once the unit has been installed. As is discussed in Section 8 out of balance line pre-tensions could be a key factor leading to mooring line failures.

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18.7.1 Difficult To Inspect Areas

Inspecting fibre rope for potential wear in situ is potentially difficult – see Figure 18-15. It is noted that certain projects have elected not to use thimbles and it will be interesting to see if this leads to increased abrasion over time.

A c c e s s

d i f f i c u l t i e s

f o r i n w a t e r

i n s p e c t i o n

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Figure 18-15 - Example of a Difficult Area to Inspect

Chain in the trumpets and at the stopper is obviously difficult to inspect as previously discussed – see Section 9.

In theory it is important to confirm that all pin locking devices are in place and secure. However, as can be seen from Figure 18-15, during a normal ROV survey, this can be difficult to achieve.

Figure 18-16 - Partially Buried Shackle Illustrates the Difficulties in checking locking pins (courtesy of ENI)

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18.7.2 Pile, Padeye and Anchor Inspection

The padeyes on the piles are typically buried several metres down. From a simplistic point of view jetting out soil from around the pile would loosen it and thus does not seem desirable !

However, if one pile or padeye degenerates and fails the rest will probably be in a similar condition. Thus the danger of the system unzipping with multiple line failures cannot be discounted.

It is important that the fatigue capacity of the padeyes and piles should be checked and be satisfactory based on a generous safety factor, probably in excess of 10. This is because it is pretty well impossible to inspect these components in situ.

18.8 Outline Method To Break Test Worn Mooring Components

As mooring lines and connectors wear, corrode and fatigue it is likely that there will become a stage when the true Minimum Break Load (MBL) of the line is no longer known with any real confidence. With the desire to sometimes extend field lives beyond the original design life there is a need to confirm that the as installed system is still fit for purpose.

However, if you no longer know what the break load is likely to be this makes testing somewhat more problematic. The following outlines a method that has been used successfully at a chain test bed facility. It is worth noting that break testing can be cheaper than Finite Element (FE) analysis and the results are likely to be more certain.

1) Undertake say 100te load steps initially, then say 50te steps nearer the expected yield point - check at each step the load extension graph is a straight line;

2) When the first reading shows the line is just starting to tail off, call that the yield/proof load - come back down and there should be a small amount of plastic deformation;

3) The next check is to repeat the same line again, to the same load amount, and that should be slightly displaced from the first run;

4) Repeat again to check that there is an accurate repeat of the elastic line;

5) Continue in whatever appropriate steps until one is chasing the load, i.e. it starts to fall away.

It is worth noting that it is easier to set the load on some test machines as the tension increases, rather than as it decreases; so it is better to do the steps only in one direction. It is understood that chain elongating - hence knowing it is not holding (chasing the load) - is normal, rather than a clean break. The chain extension can be automatically logged into a data file monitored using infrared deflection monitoring equipment – see the chain infrared target shown on Figure 9-9.

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18.8.1 Future Inspection Possibilities

As FPS’s come off station at the end of their field lives this provides a good opportunity to test worn mooring components.

There is also possible cross fertilization with flexible riser and particularly steel catenary riser experience including touchdown zones and inspection techniques. For example:

1. Sea bed troughs at riser touch down zones

2. Dynamic behaviour including snatch loading and compression which may be detectable by installed instrumentation

Listening for the Sound of Cracks

Ref. 20 states “Sounding the chain with a heavy hammer will reveal cracked or internally corroded links or fittings. A sound link returns a clear, ringing tone; a bad link has a dull flat tone.”

This is a bit like a Wheel Tapper detecting cracks on railway locomotive/wagon wheels – see Figure 18-17. Sounding tests represent an interesting approach to inspectionwhich might avoid the need to remove marine growth – see section 18.4. Hence, it is suggested that further investigation of this topic should be undertaken.

Figure 18-17 - Example of the Wheel Tappers Approach Used for Detecting Cracks on Railway Carriages and Locomotives

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18.8.2 Repair Case Study – Replacement of FPSO Trumpet Chain

For the chain damage reported in section 9.2.2 a long term repair was required. This involved changing out the worn chain at the trumpet with larger diameter chain with a specially applied hardened coating (cobalt chromium) to reduce the severity of any future wear. A special connector (see Figure 14-10) was developed to allow the new chain to be connected up to standard common link chain. This approach avoided disturbing the wire section of the mooring line on the sea-bed, which is relatively susceptible to damage (birdcaging). The original system designer was included in the review process for the repair operation. This represents good practice which, where possible, it is recommended should be followed for any future FPS mooring repair operations.

There were two potential options for changing out the links going into the turret, namely:

1) Crop some links from the top section of chain, add a connector and re-install

2) Disconnect the chain at the sea bed

During the repair operation there was a strong desire not to disturb the spiral strand wire since this can be relatively easily damaged – see Figure 6-5. Hence option 2 was selected.

Figure 18-18 and Figure 18-19 give an idea of the complexity and hence the cost of such a repair operation including anchor handling plus heading control tugs, Dive Support Vessel (DSV), divers and winch operations on the FPSO.

Figure 18-18 - Example of Anchor Handling and Heading Control Tugs during a Mooring Line Repair Operation (courtesy of I. Williams)

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Figure 18-19 - Use of Divers from a RIB to open up the Chain Stopper during a FPSO Mooring Line Repair (coutesy of I. Williams)

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19 SPARING OPTIONS

19.1 Contingency Planning - Spares and Procedures

Based on the indicative failure statistics reported in Section 13 it is quite conceivable that a FPS may lose a line during its operational life. The failures are most likely to be in the following areas:

1. At connectors or terminations

2. At wildcats/gypsywheels

3. Somewhere around the trumpet general area

4. In or just above the thrash zone area at the no load equilibrium position

5. At mid line buoys

6. At clump weights or hung off chain connections

Certain FPS Operators have spares, but they tend to be in the minority. In addition, although spare sections of line, particularly for example polyester, may be available suitable connectors are not always sitting in a warehouse or on board the FPS. In certain cases although spares may have been ordered their present whereabouts or condition is uncertain. On one project the spares disappeared over the horizon on an anchor handling tug never to be seen again. On another project the spare chain was stored out in the open and rusted to pieces.

There is likely to be a several month lead time to procure components such as large diameter chain, wire/fibre rope or purpose built connectors, see for example Figure 14-10. Hence, to minimize FPS safety and business exposure in case of line failure, it is believed to be well worthwhile to have spare lines, connectors and procedures available for immediate use if required. For deep water projects the procedures should ideally be developed which are based on a generic anchor handling vessel rather than a high specification installation vessel. Installation/construction vessels are unlikely to be readily available at short notice and tend to be expensive. It is worth nothing that one Operator has seen more degradation of spare polyester rope sitting onshore compared to the same rope deployed under load offshore.

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If a line does fail and no spares are available it may be possible to “mix and match” making use of available equipment from the established marine supply and rental companies. This may require the temporary use of second hand components such as chain. However, the impact of introducing non standard elements (see Figure 19-1) into a mooring system is best considered before a failure occurs. Long term mooring (LTM) shackles should ideally be used as the connectors. Repairs of this nature should give time for the procurement of the correct equipment, which may take around six months depending on industry demand. Because the mooring system has been damaged and then modified, it may be necessary to obtain concessions from the relevant Classification Society/Independent Competent Person (ICP). A reduced operating envelope may have to be accepted during the period that the temporary repairs are effective.

Figure 19-1 - Example of a Plate Shackle which may be useful for a Temporary Repair (courtesy of Balmoral Marine)

In a post project Lessons learned exercise on one FPSO the following was reported:

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“Spares (all spares. commissioning and 2 year) should be purchased with the initial order so they are available during construction, pre-commissioning and commissioning. Sort out the mechanism for budget allocation early so it does not impact spares purchasing. Consider spare instrumentation/transmitters; since these are long lead and critical for commissioning.”

19.1.1 Operators’ Spares Club

Not surprisingly no two FPS mooring systems are identical, since they are in different water depths and exposed to different environmental conditions. However, certain components can be common between different units, for example, use of 120mm studless chain. Other items such as LTM connectors (special shackles and H shackles – see Section 14.1) are likely to be needed for any repair work. Hence it would be logical for Operators to form a Spares Club which could order key spares which would then be available on a “first come, first served basis.” The established Marine Equipment rental companies would probably be suitable organisations to store, look after and promptly dispatch the spares when required.

19.1.2 Designing FPSs for Mooring Line Repairs

For a long field life the need to undertake mooring line repair is fairly high, even for relatively benign climates, which will still suffer from wear and corrosion. Thus, it is important that FPS facilities should be designed from the outset, such that mooring line change out is relatively straight forward. However, this is not always the case which may prove problematic in the long run. For example some Gulf of Mexico Spars have utilised a temporary mooring line pull in winch deck, which is removed prior to setting the main process equipment deck – see Figure 19-2.

Figure 19-2 - Temporary Mooring Line Winch Deck on a Gulf of Mexico Spar

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20 THE IMPORTANCE OF A COMPREHENSIVE

MOORING DESIGN SPECIFICATION

One of the best ways to solve problems is to prevent them starting in the first place. Hence, if the mooring design brief at the beginning of a project is well thought out, it can help to avoid difficulties which may develop during the course of the field life. This section outlines what should be included in the original mooring design brief from a mooring integrity point of view.

It is important that all interested parties should approve and support the mooring design brief or specification. To ensure that a system proves to be reliable in operation the design specification should consider and make reference to operations and long term integrity.

To assist with long-term reliability it is necessary to be able to undertake inspection to a level which gives real confidence in the condition of the as-installed system. This ensures that intervention can be carried out early on, before detected anomalies get worse and place the system at risk. Mooring line inspection should ideally be undertaken in the water, since recovering lines is extremely expensive and may cause damage such as wires birdcaging. However, mooring design briefs typically pay little attention to the importance of inspection. Thus it can frequently be the case that key components, such as chain stoppers, can be virtually inaccessible hidden away by long hawse pipes or trumpets.

If the mooring design specification insists that key components of the mooring system should be readily accessible for inspection, this will force designers to pay more attention to this long term integrity/reliability issue. In addition, the specification should state that the FPS design should allow for straight forward replacement in the field of mooring lines, preferably using anchor handlers rather than specialist and expensive construction vessels.

Mooring line instrumentation is another area which typically receives little attention at the design brief stage. However, good quality instrumentation can potentially improve mooring integrity to a significant extent. At the same time instrumentation can help to detect problems early on which, without early intervention, can prove extremely expensive to repair at a later date. This is particularly the case if the intervention work results in deferred production.

The cost of instrumentation is relatively low if it is incorporated in the design from the outset. However, it is vital that instrumentation needs to be reliable. Offshore represents an exacting environment and thus best quality should be specified at the beginning. The following parameters should typically be specified:

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Line tensions monitored and the data permanently recorded at a suitable sampling interval

24 hours monitored over tension alarms

FPS offsets and bearings monitored and permanently recorded

24 hours monitored lines intact alarms

24 hour monitored FPS excursion alarms

For moderate environments, such as off West Africa, there is a much smaller difference between operational and survival sea states compared to say the North Sea. This means that if the operational sea state, or the response of the vessel in the operational sea state, is underestimated there is significantly less of an in built safety margin compared to harsher climates, particularly with regard to fatigue. Therefore, depending on the criticality of the fatigue assessment, it may be appropriate to undertake sensitivity studies to assess the effect of an under prediction of actual vessel motions.

20.1 Installation Parameters

It is important that the mooring design process should take due consideration of the capabilities of the likely installation vessels and their past performance on previous projects. It is appreciated that during the early design phase that the particular installation vessels may well have not been identified. Hence, a degree of conservatism should be incorporated in the design process, such that the required installation tolerances do not prohibit otherwise capable and perhaps cheaper vessels. This means that the mooring design brief should include suitable loadcases to account for lines at non uniform pre-tensions and anchors which may be tens of metres away from their planned positions. This is particularly likely for the case of drag embedment anchors, since it is extremely difficult if not impossible to predict where they will hold and whether they will follow a straight line as they are dragged during pre-tensioning.

20.1.1 Mooring Design Team Participation during Installation

During the mooring installation process it is important that the installation crew should be fully aware of the key design criteria, such as handling of fibre ropes, pretension accuracy, anchor placement accuracy, avoidance of chain twists, etc. Therefore, it is recommended that a suitably experienced member of the mooring design team should go offshore during the mooring installation and FPS hook up operation. This person is thus ideally placed to answer operational questions as they arise. Again this should be specified in the mooring design specification so that contractors expect this and work with the mooring designers during the development of the installation procedures.

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In practice it is unlikely that a mooring system will be installed exactly to specification. If the as installed condition does not correspond to any of the loadcases analysed during the design process, it is important that key load cases should be re-run to ensure that the system is still fit for purpose. Having sent a mooring designer offshore during the installation helps to ensure that whatever is analysed back in the office corresponds to the as installed configuration. In addition, feedback from the field helps to ensure that the design of systems is continually improving and that sub optimum solutions are not repeated. Again specifying a post installation check of the system performance using as built parameters should be specified in the mooring design specification

20.1.2 Accurate As-Builts and Baseline Surveys

On the majority of FPSs the initial survey after mooring installation appears to have been only Close Visual Inspection (CVI) and General Visual Inspection (GVI), no measurements are typically undertaken. But there is a need for accurate as built baseline dimensions so that the extent of any future wear can be assessed – see section 18.5.

20.1.3 Mooring Design and Maintenance Based on a Life Cycle Approach

At present mooring systems are typically designed by specialists who may have little further involvement after installation. It is only if serious problems occur that the designers may learn more about how the moorings have performed in situ. This is particularly the case if a FPS is provided by a contractor who then hands over operation to an Oil Company.

However, mooring systems are not as simple as they first appear and they need careful management through out their design lives. Thus a life cycle approach to mooring design and operation is recommended. In this way designers can feedback their inspection requirements to Operators and then learn from whatever is found during inspection. Hence, over time, mooring design should improve. At present designers are not always involved with the in field behaviour mooring systems. Hence they may not be aware of operational or inspection type issues. Thus new projects may repeat designs from the past, which in some instances have certain limitations. Obviously if something has been demonstrated to work well over a long deployment this is a good argument for not changing it.

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21 KEY CONCLUSIONS & FUTURE WORK

RECOMMENDATIONS

21.1 Overview

In this project, an extensive investigation has been carried out of materials, design, operations and management issues affecting the long-term integrity of mooring systems for floating production systems. A broad survey has been conducted of units around the world, especially those in harsh environments. The in-depth experience of the participating equipment suppliers, designers, regulatory authorities, Operators and Noble Denton has been collected and compiled into this state of the art report. The resulting document is intended as a reference point for designers and operators alike, with guidance on current and future practices and lessons learnt from the past.

There are many success stories in operation around the world, but there are also a number of cases where the integrity of the moorings has been compromised to some extent by unforeseen reasons. In part this is to be expected in any innovative technology, but there also appear to be some critical omissions in design and integrity management strategies. Significantly, during the course of this project failures have continued to occur. Clearly there is still much to learn on this subject and key areas requiring further work are identified later on in this section.

Overall, based on the evidence acquired during the course of this JIP, as systems age, it seems quite probable there will be mooring failures in the future, unless more proactive inspection and remedial work is undertaken. Areas to watch include:

1. Excessive wear and corrosion of chain in thrash zone,

2. Tension bending in deep water taut moored systems,

3. Problems due to the chain stopper being outboard of the pivot point resulting in dynamic link wear + possible wear on the trumpet structure,

4. Weighted chain problems.

Given the difficulties associated with repair operations in deep water and the lack of suitable spares, such failures would be expensive to repair and might attract publicity which could be detrimental to floating production systems in general. Overall, Operators need to get into the way of thinking that moorings are an integral part of their production facility. This will encourage them to give them the attention that they merit given the serious consequences associated with failure.

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21.2 Key Conclusions

Moorings on FPSs are category 1 safety critical systems. Multiple mooring line failure could put lives at risk both on the drifting unit and on surrounding installations. There is also a potential pollution risk. Research to date indicates that there is an imbalance between the critical nature of mooring systems and the attention which they receive.On many FPSs there is an important need to improve the knowledge base of offshore personnel on the intricacies of their mooring systems and their potential vulnerability. This will help to ensure that mooring systems receive the amount of attention they deserve, particularly during inspection operations. One of the aims of this report is to educate both offshore and onshore operational staff.

The interface between the surface vessel and the mooring line requires particular attention for all types of FPS. Carefully planned innovative inspection, making use of all possible tools, has been demonstrated to be able to detect problems relatively early on before they become a potential source of failure. The use of micro-ROVs to gain access to restricted areas not accessible by conventional ROVs and divers has been part of the key to this success. The inspection which has been undertaken has shown the importance of achieving compatible surface hardness, since it affects wear. Unfortunately, at present chain hardness and wear do not normally seem to be considered in any detail during the standard design process.

In situ in-water inspection techniques are continuing to improve, but further developments are needed to provide dimensional data on links all around the inter-grip area and to improve the marine growth cleaning off speed. At present no in-water techniques exist to check for possible fatigue cracks and the development of such technology should be encouraged which could include acoustic means – see section 0. Inspection access needs to be improved and this should be stipulated in the mooring design brief or specification.

On two North Sea FPSs chain wear and corrosion has been found to be significantly higher than what is specified by most mooring design codes. This wear seems to be more pronounced on less heavily loaded leeward lines compared to the more loaded windward lines. Hence, it appears that more interlink rotation is occurring on the leeward lines. More in field data is needed to find out if this is a general finding which could have long term implications for other FPSs in the North Sea and elsewhere.

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At present there is little data available which indicates how the break strength of long term deployed mooring components will be reduced by wear, corrosion including pitting and the possible development of small fatigue cracks. Thus to assess long-term integrity with any confidence it is recommended that break tests on a statistically representative sample number of worn components should be undertaken. Recovered lines from the thrash zone and from the fairleads/chain stopper area would be ideal for testing. Such material is likely to be available whenever a FPS comes off station or has repairs done to its moorings. As well as break tests, Magnetic Particle Inspection (MPI), photographs and comprehensive dimensional measurements should be undertaken. It is important that this data should be fed back to the industry. Certain North Sea Operators have shown a willingness to make this data available.

Offset monitoring has limitations in detecting quickly line failure unless a FPS is in deep water. However, it is cheap and easily installed. Hence it should be installed as standard on all units. In addition, all units should have readily available on board the maximum sea state in which they can continue to produce in case one line fails. This assessment should be based on intact system mooring line safety factors. On board emergency procedures should identify what action should be taken in case of riser rupture while the risers are still pressurized, although the likelihood of this happening is low. During design the susceptibility of risers to be swept under moorings should be assessed, since if a line fell on a pressurised riser the consequences are likely to be serious.

Some large floating production projects have design lives of 20+ years. If a field is still profitable there will always be a desire to continue production in excess of the design life, but at this stage the moorings may no longer be fit for purpose. Hence, for long field life projects a FPS Operator should review the budget for line repairs / replacements part way through the field life based on up to date inspection findings taking into account the experienced, rather than the anticipated, wear / corrosion.

A relatively simple wear model is reported in Shoup and Mueller’s OTC paper of 1984. Given that there is now a limited amount of in field chain wear data from a few long term deployed units, it would be desirable to undertake an up to date wear assessment to see how the calculated values tie up. Once a validated methodology has been developed it would be possible to use such an approach to estimate wear rates for 20 year plus required field lives.

A possible contributory mechanism for the relatively high line rate among drilling semi-submersibles has been identified. This is believed to be due to rigs thinking they have set up balanced pre-tensions, when in fact this has not been achieved. Hence, it is recommended that in field Pay-In/Pay-Out tests should be undertaken to check whether the line tension readings can be relied upon – see section 0.

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Finally a general lack of suitable spare lines, connectors and repair procedures has been noted. Given the substantial procurement lead-time associated with these items it is recommended that Operators should review their assets to see how they could deal in the short term with one or more failed lines. The reported statistics show that line failures have been higher than might normally be expected for custom designed systems which are not regularly recovered and redeployed. Thus the business interruption potential due to mooring problems should not be underestimated.

In general there seems to be a need for periodic Mooring Audits to re-assess original design parameters and review inspection records to assess whether the system is still fit for purpose. When considering possible mooring line remedial works and when it should be done it is logical to look at the anticipated future life of the chains based on wear/corrosion rates experienced to date.

21.3 Recommendations for Further Study

Overall the JIP has helped to publicise the importance of mooring integrity to a larger audience. However, it has also identified a number of areas which warrant further investigation to improve safety and reduce life cycle cost. The following list identifies the key topics:

1. Obtaining field data for different regions/FPS types on the combined wear/corrosion rate particularly in the thrash zone/fairlead areas and the implications for units which cannot adjust line lengths.

2. Calibrate an up to date wear/corrosion analysis model with long-term offshore data (see section 7.6.2).

3. Engineering guidance for relative surface hardness for components expected to be subject to long-term wear.

4. Assess how increases in proof stress may help the fatigue endurance of mooring components – see Section 14.5.

5. Development of improved in water inspection techniques for hard to access areas with the goal of being able to detect cracks.

6. The potential for cost effective micro/mini ROV mooring line inspection from the FPS itself.

7. Determining how chain strength is reduced by wear/corrosion is infancy and more research and physical break testing of used lines and connectors is required. This work should also consider the applied ramp rate during break testing

8. Based on in field data, assess how removal of marine growth for inspection affects corrosion rates.

9. Possible methods to check the integrity of connectors in the water, including new designs of fibre rope connectors.

10. Collation and assessment of Pay-In/Pay-Out test data – see Section 0.

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11. Publicise the benefits of offshore visits/audits to brief personnel on mooring integrity and to review existing instrumentation and procedures.

12. The dynamics leading to relative axial movement and wear between chain links near the chainhawse needs to be understood so that it can be taken account of either by adopting a new configuration (stoppers out board of the pivot point plus possibly a twin axis design – see Section 9.2) or by using a an accurate wear/corrosion rate at the design stage.

13. Report on the in field performance of new mooring line instrumentation and failure detection systems. Assess the feasibility of a Response Learning System (see Section 17.3.1).

14. ROV collection of soil samples from the proximity of mooring lines to assess the concentration of sulphate reducing bacteria (SRBs).

15. It is believed that there could be beneficial cross fertilization with flexible riser and particularly steel catenary riser experience including touchdown zones and inspection techniques.

16. Identify key common spares plus contingency connectors which could be held by a shared “Operators’ Spares Club” – see section 19.1.1.

17. Encourage the installation of simple inclinometers to aid in detecting line failure if it occurs in the sea-bed mud – see Section 17.2.2

With respect to steel components there is a need for additional reliable strength data to assist with the following:

to evaluate fatigue in connectors, terminations, etc,

to evaluate bending and tension-bending fatigue in chains and also to measure how chain surface finish can affect the friction between links,

to better understand T-T fatigue for chains, currently given by T-N curves, derived from full scale tests made in the late 1990's. A hot-spot S-N approach, i.e. stresses by Finite Element analysis, strength derived from tests on small scale specimen could be fruitfully used.

There are still uncertainties in estimating mooring loads using analysis software and model tests. Hence, it would be desirable to compare the behaviour of a full scale FPS in known weather conditions versus predictions. It is recommended that further work should be done on this topic, although it is appreciated that there are difficulties associated with obtaining reliable weather and instrumentation readings. The effect of mooring shock loading when subject to breaking waves should also be assessed – see Section 3.1.10.

Overall there is a continuing need to monitor and report back to the mooring community on issues which arise in future years as systems age, e.g. wear at FPSO trumpets. This has been a particularly useful aspect of the Steering Committee meetings to date and it would be desirable for this dialogue to continue. It is hoped that this will be achieved through a Phase 2 Mooring Integrity JIP.

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22 REFERENCES AND BIBLIOGRAPHY

Ref. 1 HSE Research Report 047, “Analysis of Accident Statistics for Floating Monohull and Fixed Installations” 2003.

Ref. 2 The Centre for Marine and Petroleum Technology “Floating Structures: a Guide for Design and Analysis” Volumes1 and 2.

Ref. 3 “Experience with Mooring Integrity Assessment for Semi Submersibles” R.B. Inglis, Hydrodynamics: Computations, Model Tests and Reality – Proceedings of MARIN workshop on Advanced Vessels, Station Keeping, Propulsor-Hull Interaction, and Nautical Simulators, Elsevier Science Publishers B.V. , Amsterdam, 1992.

Ref. 4 International Organization for Standardization Draft International Standard ISO/DIS 19901-7 Petroleum and natural gas industries – Specific requirements for offshore structures – Part 7: stationkeeping systems for floating offshore structures and mobile offshore units.

Ref. 5 DNV Offshore Standard Position Mooring, DNV-OS-E301, June 2001.

Ref. 6 Appendix A, Supplementary Requirements of the Norwegian Maritime Directorate (NMD) and the Norwegian Petroleum Directorate (NPD) POSMOOR 1996.

Ref. 7 “Experimental Study of Load on an FPSO in Design Environmental Conditions” Skourup, J., Sterndorff, M.J., Smith, S.F., Cheng X., Ahilan, R.V., Soares, C.G., and Pascoal, R., OMAE-FPSO’04-0069, Houston).

Ref. 8 Noble Denton & Associates Inc Joint Industry Study Report “Corrosion Fatigue Testing of 76 mm Grade R3 & R4 Studless Mooring Chain dated 15 May 2002 (Report No: H5787/NDAI/MJW Rev 0).

Ref. 9 “New Mooring Chain Designs” by Luis Cañada, Javier Vicinay, Alejandro Sanz, Eduardo López Vicinay Cadenas, SA., OTC 8149, 1996.

Ref. 10 Billington Osborne-Moss Engineering Limited (BOMEL) “Design Guidelines for Anchor Chains” – Final Report (Report No: C538R002.04 Rev A) dated June 1992.

Ref. 11 W.K. Lee and C.Z. Hua, "Theoretical and Experimental Stress Analysis to Evaluate the Effect of Loose Studs in Anchor Chain," Conf. Proc. Engineering Integrity Assessment, East Kilbride, Glasgow, 11-12 May 1994, pp. 171-191.

Ref. 12 “Assessment of Mooring Chain from Mobile Drilling Unit,” 19th Jan. 1994, Sandberg Consulting Engineers (Report No: M/5771/SCC/pb/03).

Ref. 13 Vicinay Chain Catalogue (Red).

Ref. 14 “Development of API RP 2SM for Synthetic Fiber Rope Moorings” by Ming-Yoa Lee, American Bureau of Shipping, Paul Devlin, Texaco Inc and Chi-Tat Thomas Kwan, Consultant.

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Ref. 15 Guidance Notes on the Application of Synthetic Ropes for Offshore Mooring by American Bureau of Shipping Incorporated by the Legislature of and State of New York 1862 dated March 1999.

Ref. 16 Revised API RP2SK, Appendix A, under development.

Ref. 17 Michael F. Ashby and David R.H. Jones, “Engineering Materials 1 – An Introduction to their Properties and Applications”, Pergamon Pess Ltd., 1980.

Ref. 18 DNV Certification of Offshore Mooring Chain, Note 2.6 dated August 1995.

Ref. 19 “Marine Casualty Response: Salvage Engineering” – American Society of Naval Engineers and JMS Naval Architects and Salvage Engineers.

Ref. 20 “No Port in a Storm” by Bob MacAlindin, published by Whittles (ISBN: 1870325370).

Ref. 21 Offshore Technology Report – Review of Mooring Incidents in the Storms of October 1991 and January 1992 Issued January 1992.

Ref. 22 Offshore Technology Conference 2004 Paper “Post Mortem Failure Assessment of MODUs during Hurricane Lili” BP Malcolm Sharples, Offshore Risk & Technology Consulting, Charles E Smith, Minerals Management Service and Robert G Bea, University of California at Berkeley.

Ref. 23 Offshore Technology Report 2000/086 – Operational Safety of FPSOs: Initial Summary Report prepared by Norwegian University of Science and Technology (NTNU) for Health and Safety Executive.

Ref. 24 Jatar, S., Haslum, H., and Tule, J., “The Design, Testing and Installation of the Red Hawk Spar Polyester Taut Leg (TLM) System, 16th Annual Deep Offshore Technology (DOT), New Orleans, Nov. 30th – Dec. 2nd.

Ref. 25 Chaplin, Rebel & Ridge, “Tension/Torsion Interactions in Multi-component Mooring Lines”, OTC012173.

Ref. 26 “Mad Dog Polyester Mooring Installation,” Petruska, d., Rijtema, S., Wylie, H., Geyer., J., 16th Annual Deep Offshore Technology (DOT), New Orleans, Nov. 30th – Dec. 2nd.

Ref. 27 Deep Offshore Technology (DOT 2004), New Orleans ‘The Design, Testing & Installation of the Red Hawk Spar Polyester Tank Leg Mooring (TLM) System’, Sanjai Jatar, Herbjorn Maslum, Jenifer Tule.

Ref. 28 British Standard BS 6349-1 2000 - Maritime Structures – Part 1: Code of Practice for General Criteria.

Ref. 29 DNV Rules for Classification of Mobile Offshore Units – Special Equipment and Systems Additional Class, Part 6 Chapter 2 July 1989 Position Mooring (POSMOOR).

Ref. 30 API Recommended Practice 2I, ‘In-service Inspection of Mooring Hardware for Floating Drilling Units’, Second Edition, December 1996.

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Ref. 31 API Recommended Practice for Design and Analysis of Stationkeeping Systems for Floating Offshore Structures – Second Edition December 1996 API RP2SK.

Ref. 32 “Long term Mooring chains and components” by Mr Pär Ohlsson, Technical Manager, Scana Ramnäs AB, 3rd international Offshore Moooring Seminar.

Ref. 33 “Mooring Chain Corrosion Design Considerations for an FPSO in tropical Water” by Mark Wang and Richard D’Souza, Deepwater Technology at Kellogg Brown – Proceedings of OMAE-FPSO I2004 OMAE Specialty Symposium on FPSO Integrity, Houston USA 2004 - Paper No: 04-0046.

Ref. 34 Failure Analysis of a CALM Buoy Anchor Chain System by G. J. Shoup and R. A. Mueller, Cities Service Oil & Gas Corp. - OTC 4764, 1984.

Ref. 35 Dowdy, M.J. and Graham, D.J., “A Method for Evaluating and extending the useful Life of In-Service Anchor Chain,” OTC 5719, 1988.

Ref. 36 HSE Research Report 219 “Design and integrity management of mobile installation moorings” P.J. Donaldson, M. Brown and M. Pithie (Noble Denton).

Ref. 37 HSE Safety Notice 3.2005 “Floating Production Storage and Offloading (FPSO) – Mooring Inspection” issued April 2005 – see Appendix D.

Ref. 38 ‘The Professional Diver’s Handbook’, published by Submex Limited (ISBN: 09508242 0 8) 1982.

Ref. 39 “Design and Analysis of West Seno Floating Structures” Jafar Korloo (Unocal), Jared Black (Unocal), Chunfa Wu (SEA Engineering), J. Hans Treu (SEA Engineering) Presented at Offshore Technology Conference held in Houston 3-6 May 2004, OTC 16523.

Ref. 40 “Na Kika – Deepwater Mooring and Host Installation” A.K. Paton (Shell International E&P Inc.), J.D. Smith (Shell), J.A. Newlin (Shell), L.S. Wong (Shell), E.S. Piter (Edmar Engineering Inc); C. van Beek (Heerema Marine Contractors BV). Presented at Offshore Technology Conference held in Houston 3-6 May 2004, OTC 16702.

Ref. 41 Noble Denton Europe Limited Joint Industry Project “The Evaluation of Wire Mooring Line Strength and Endurance, Additional Testing of Steel Wire Rope” – Final Report (Report No: L17294Rev1/NDE/RWPS) dated 16 February 1996.

Ref. 42 Noble Denton Europe Limited Joint Industry Project “The Evaluation of Wire Mooring Line Strength and Endurance (Old Ropes II)” – Final Report (Report No: L18085/NDE/RWPS) dated 2 April 1997.

Ref. 43 Reading Rope Research “The Inspection & Discard of Wire Mooring Lines” C. Richard Chaplin December 1992. Prepared as a supplement for participants in a joint industry study on an Appraisal of Discarded Mooring Ropes.

Ref. 44 Final Report of a Joint Industry Study on Prediction of Wire Rope Endurance for Mooring Offshore Structures, working summary by C Richard Chaplin, Department of Engineering at university of Reading August 1991.

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Ref. 45 Noble Denton Europe Limited Report for TotalFinaElf Exploration UK Plc “Investigation into the Run-out of Number 6 Mooring chain on “Transocean John Shaw” (Report No: A4071/01/NDE/CLC/Ls) dated 20 February 2003.

Ref. 46 HSE Offshore Technology Report – OTO 98 086 “Quick Release Systems for Moorings” issued April 1998.

Ref. 47 HSE Offshore Technology Report 2001/073 “Failure modes, reliability and integrity of floating storage unit (FPSO, FSU) turret and swivel systems”.

Ref. 48 “Turret Operations in the North Sea: Experience from Norne and Asgard A” by Borre Knudsen and Bard A. Leite - Procs of the Eleventh (2001) International Offshore and Polar Engineering Conference, Stavanger, Norway 17-22 June 2001.

Ref. 49 Health & Safety Executive ‘Analysis of accident statistics for floating monohull and fixed installations’ prepared by Martin Muncer , Research Report 047, 2003

Ref. 50 Petroleum Safety Authority Norway “Trends in risk Levels – Norwegian Continental Shelf summary Report Phase 4 – 2003”.

Ref. 51 “Forging Solutions #17” published by the Forging Industry Association.

Ref. 52 British Paper GB190607951, 1905, ‘Improvements in Chain Coupling-links’.

Ref. 53 Bureau Veritas Guidance Note “Certification of Synthetic Fibre Ropes for Mooring Systems” 1997 NI 432 DTO R00 E 1997.

Ref. 54 OTC 6905, 1992, “The Influence of Proof Loading on the Fatigue Life of Anchor Chain”, Shoup, George J., Tipton, S.M., and Sorem, J.R.

Ref. 55 WADO Deepwater Mooring Conference, Paris, June 2003.

Ref. 56 Floating Production Mooring Integrity JIP – Key Findings, OTC 17499, 2005, Martin G. Brown, Tony D. Hall, Douglas G. Marr, Max English, and Richard O. Snell – see Appendix C.

Ref. 57 DVN Fatigue Strength analysis of Offshore Steel Structures, DNV-RP-C203, October 2001.

Ref. 58 N.F Casey, National Engineering Laboratory, Department of Trade and Industry, “Monitoring the Properties of Wire Ropes Subjected to Bending-Tension Fatigue around Sheaves”, DE/7/88, November 1988.

Ref. 59 Richard Chaplin & Andrew Potts, Wire Rope Offshore – A Critical Review of Wire Rope Endurance Research Affecting Offshore Applications, HSE, OTH 91 341, 1991.

Ref. 60 “Cost Effective Mooring Integrity Inspection Methods,” Hall, A.D., OTC 2005, May 2-5, Houston, paper 17498.

Ref. 61 Performance and Testing of Components of the Ivanhoe/Rob Roy Floating Production System Mooring, J.R. MacGregor and S.N. Smith, Amerada Hess Ltd, and J.E Paton, JP Kenny (Caledonia), OTC 7492 1994.

A4163-01 276

Ref. 62 Joint Industry Project - Sub Sea Electrol Magnetic Appraisal of Wire Mooring Lines (The SEAL Project) Report No: L17770/NDE/RWPS dated 31 May 1996.

Ref. 63 HSE Research Report 328 – “Acoustic monitoring of the hulls of Floating Production Storage and Offloading facilities (FPSOs) for corrosion and damage” prepared by Mecon Limited 2005.

Ref. 64 Section 4, Wire Rope Research at the NEL an Overview, N.F. Casey, Nov. 1988.

Ref. 65 American Petroleum Institue “Specification for Mooring Chain” API Specification 2F, Sixth Edition June 1997.

Ref. 66 International Association of Classification Societies (IACS) “Requirements concerning Materials and Welding” W22 Offshore Mooring Chain.

Ref. 67 “The modelling and analysis of splices used in synthetic ropes”; Leech, C M Procedings of the Royal Society, published online, doi:10.1098/rspa.2002.1105 (2003).

Ref. 68 “The Analysis of Splices used in Large Synthetic Ropes”, C M Leech, Europmech 334 (Textile Materials and Textile Composites) Université Lyon, France. 1995.

Ref. 69 “Engineers Design Guide for Deepwater Fiber Moorings”, 1st Edition, NDE/TTI Joint Industry Project, January 1999.

Ref. 70 OTC paper 10798, 1999 “Genesis Spar Hull and Mooring System : Project Execution”, (W.F. Krieger, Chevron Petroleum Technology Co., J.C. Heslop, Chevron U.S.A. Inc., B.E. Lundvall, Exxon Upstream Development Co. and D.T. McDonald, Chevron U.S.A.

Ref. 71 NACE International, The Corrosion Society “Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Producetion NACE Standard RP0176-2003 Item No 21018.

Ref. 72 European Committee for Standardization EN 13173 ICS 47.020.01;77.060 “Cathodic Protection for Steel Offshore Floating Structres” January 2001.

Ref. 73 Health & Safety Executive Offshore Technology Report ITC 96 033 “A Review of Available Laboratory Test Data on Mooring chain Applications” dated April 1998.

Ref. 74 Health & Safety Exeuctive Offshore Technology Report ITO 96 018 “Improved Reliability of Mooring Chain Systems” dated May 1997.

A4163-01 278

23 APPENDIX A - SUMMARY OF PAST RELEVANT

JIPS

Engineers Design Guide to the use of Deepwater Fibre Mooring Lines

1996, 31 participants, RWPS most knowledge

Corrosion Fatigue of Studless Mooring Chain

2002 final report, Noble Denton Houston

Subsea Electro-Magnetic Appraisal of Mooring Lines (SEAL)

1995 Noble Denton London

Evaluation of Wire Mooring Line Strength and Endurance

1996/97 Old Ropes 2 and 2.5

“Mooring Code Joint Industry Study”,

Noble Denton & Associates, October 1995

Fatigue Tests for Large Diameter Mooring Anchor Chains

1994 Final report H3241/NDAI/JIS, Houston work,

High-Technology Fibres for Deep Water Tethers and Moorings

1995, otherwise known as Fibre Tethers 2000

• The Appraisal of Discarded Mooring Lines

• 1992 Richard Chaplin Blue Book

• The Prediction of Wire Rope Endurance for Mooring Offshore Structures

• 1990 final report, NEL involved

• Mooring Integrity: A State-of-the-Art Review

• 1991-1993, Dr. Ahilan report for Shell

• HSE Mooring Guidance

• 1989-1993

A4163-01 279

24 APPENDIX B – MOORING INTEGRITY

QUESTIONNAIRE (EXCEL)

A. GENERAL DETAILS

A1. Unit Name A2. Field Name

A3. Unit Type

A4. Water Depth m A5. Geographical Area

A6. Date Installed

A7. Is the FPS classed?

A8. Has the unit ever been used elsewhere?

A9. Was the unit ever removed from site and then re-installed?

A10. Can the mooring system be disconnected in case of typhoons or ice bergs ?

A11. If the moorings can be disconnected, how often has this happened to date ?

B. MOORING SYSTEM MAKE-UP

B1. Line Make-up Non coated spiral strand wire

B2. Configuration Sub surface buoys used no swivels

B3. Approx. symmetrical Assymetrical system due to likely typhoon direction

system ?

B4. Can the lines tensions be adjusted during normal operations?

B5. How often is the line "worked" to prevent localised wear?

B6. Anchor Type?

B7. Length & make up of first line segment FROM ANCHOR (eg. 25m of 120mm ORQ studless chain)

m of

B8. Length & make up of grounded length section

m of

B9. Length & make up of catenary section

m of

B10. Length & make up of final line section into FPS

m of

B11. If applicable position, make up & length of any weighted line sections or buoyancy modules

JOINT INDUSTRY PROJECT: FPS MOORING INTEGRITY

QUESTIONNAIRE

Nan-Hai-Sheng-Li Liuhua, South China Sea

Turret FPSO

310 South East Asia

Mar 1996

Wire Rope Polyester Rope Chain

Catenary

Classification Society: ABS

No

No

Not Possible

Drag Embedment

Studlink

? 4.5" Bridon Non-Coated spiral strand wire

? 4.5" Ramnas studded chain

? 4.5" Bridon Non-Coated Spiral Strand Wire + subsea buoy + spiral stra

? 4.5" Ramnas Studded Chain

A drawing of the 25te net buoyancy subsea buoys

would be appreciated.

Yes

No

No

No

N.A.

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

C. HEADING CONTROL + THRUSTERS

C1. Thrusters Type

C2. Are thrusters used for normal heading control ?

C3. Are thruster used to reduce line tensions?

C4. Any thruster problems encountered which could affect mooring integrity?

C5. Any significant problems encountered during line "winching" operations?

C6. Any turret problem e.g. bearing or jacking/locking difficulties, but excluding swivel faults?

C7. Turret Designer?

C8. The turret is

D. MOORING DESIGN/CODES & STANDARDS

D1. Which Mooring Code was the system designed to ? Please Advise ?

D2. Presently anticipated field life ? years

D3. Calculated fatigue design life excluding safety factor ? years Please Advise ?

(if safety factor is included please advise)

None

No

No

Not Applicable

SOFEC

Free weathervaning

Don't know

?

20

No

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

E. LINE LOCK OFF & TENSIONING

E1. Means of Tensioning? Please Advise ?

E2. How is the line locked-off?

E3. Where is it locked-off?

E4. Freedom to Rotate?

Wire Rope Drum-type W

Chain Stopper

Submerged - Base of turret

Vertically

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

F. CONNECTORS & INTERFACES INCLUDING FAIRLEADS & SEA-BED TOUCH DOWN

F1. Connector type to anchor?

F2. Connector type between anchor line and grounded sections?

F3. Connector type between grounded and catenary sections?

F4. Connector type between catenary and final line section?

F5. Split pins/nylocs used on all shackle pins?

F6. Have you experienced connector failure or significant degradation ?

F7. Type of fairleads?

F8. Fairlead Fredom to Rotate?

F9. What is the approximate make up of the sea bed at the touch down points?

F10. Has signigicant wear been experienced at the sea bed touch down?

F11. Have trenches been excavated at sea-bed touch down?

Other, please specify Anchor Shackle

Other, please specify Socket - triplate - shackle

Other, please specify Shackle - triplate - socket. Please advise

connections to subsea 25te net buoyancy

buoy?

Other, please specify Socket - triplate - shackle

Don't know

Combined Stopper & Trumpet Assembly

Vertically

Other, please advise Please advise ?

Yes ?? mmHow Much?

Yes ??? mHow Deep?

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

G. TRANSPORTATION & INSTALLATION

G1. Who was the principal mooring installation & hook up contractor?

G2. Any line damage during transportation?

G3. Any line damage during installation?

G4. Do you know of any twists in the mooring lines?

G5. Are all the lines straight from the anchors to the fairleads ?

G6. What is the approximate maximum tension variation between lines in dead calm conditions ? Te

G7. Any lessons learned during transportation and installation ?

Clough Stena

Yes

Please, provide details ???

Don't know

Don't know

???????

Please advise ?

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

H. LINE TENSION MONITORING

H1. Are line tension read outs available in real time ?

H2. How are the tensions measured ?

H3. If applicable what is the approximate accuracy of the tension readout (e.g. +/- 20 tonnes) Te

During installation

H4. Are the line tensions recorded and the data permanently preserved ?

H5. Are the offsets measured from no load equilibrium position?

H6. Accuracy of measurements (e.g. +/- 0.5m) m

H7. Offsets recorded and data permanently preserved?

H8. Has the recorded data been validated against the original mooring design estimates?

No

Other, please advise The line tensions, in terms of chain angle

at the trumpets, are only measured during

initial installation and during inspection

surveys ???

??

No

Yes

????

No

Don't know

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

I. LINE FAILURE DETECTION

I1. Line failure detection devices on all lines?

I2. Basis of line failure detection devices?

I3. Line failure detection operational on all lines?

I4. 24 hours a day monitored alarms on failure detection devices?

I5. Please, provide details of any breakdowns of line failure detection devices, if known

I6. Is it possible to quickly distinguish between instrument failure and line breakage ?

I7. Please provide any details if there is any plan to install or add on existing system

No

Other, please specify????

No

No

Not applicable ?

No

????

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

J. INSPECTION, REPAIR & MAINTENANCE (IRM)

J1. What is the frequency of mooring line inspection?

J2. How is the scope of line inspection determined?

J3. Is mooring inspection part of planned maintenance system?

J4. What is the principal mean of inspection?

J5. How is wear measured?

J6. In case the chain stoppers are submerged, how can they be inspected?

Other, please specify

Please advise ?

Classification Society Requirement

Yes

Other, please specify General visual inspection by ROV ?

Other, please specify

Have you used the Welaptega Marine ROV camera based

system for detecting wear? If not, have you used any vaguely

similar system ?

Is visual inspection almost impossible due to the chain stoppers

being at the end of a trumpet or hawse pipe surrounded by the

spider structure ?

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

J7. During inspection, is a check made on the security of all pins?

J8. Anchor connections

J9. Any significant problems encountered with anchors during or since installation?

J10. Are the risers normally inspected at the same time as the moorings ?

J11. Has significant wear been detected where the chain emerges from the

trumpets at the base of the turret or at the fairleads ?

J12. For systems with studded chain, have loose or missing studs been detected?

J13. Have you detected defects that are common to more than one line?

J14. Has wear been greater on windward (most heavily loaded) or leeward lines?

J15. How is corrosion prevented?

J16. Any particular corrosion problems?

J17. If the lines are electrically isolated, how is this checked?

J18. How often are the lines recovered for inspection?

J19. If weighted line/clump weights are used, have they stayed intact?

Only when easily visible

They can't be inspected, they are under mudline

Sometimes

Yes, please supply details

If wear please specify the level in mm if possible ?

Don't know

Other, please specify Corrosion allowance on the chain ?

Measuring cathodic potential levels via a ROV deployed

probe ?

Not Recovered

Not Applicable

No

No

Not Applicable

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

K. PRODUCTION OPERATIONS AFTER ONE LINE FAILED

K1. Does the exisiting Emergency Response Plan/Safety Case allow continued operation after one line failed?

K2. Are there pre-defined maximum environmental limits for continued operations after one line failed?

K3. Are there 24 hours a day monitored alarms if the offsets exceed a pre-defined level?

K4. What triggers the decision to suspend production?

Yes

Yes, please supply details ????

Yes

Instrumentation readouts + Experien

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

L. HISTORY OF STATION KEEPING FAILURES

L1. How many stationkeeping failures have you experienced?

L2. Have you experienced multiple failures at the same time?

L3. Are these failures covered by completed Incident Summary Worksheets ?

M. SPARES

M1. What mooring line spares do you have which are immediately available?

M2. Do written contingency procedures exist for rapid deployment of a replacement mooring line?

M3. Are any mooring components routinely changed out?

N. PERSONNEL INFORMATION

N1. Name

N2. Position

N3. E-mail adress

N4. Email address of back to back cover

?

No

Connectors

Wire Rope

Chain

Fibre Rope

Instrumentation

Other, please specify Do you hold any spares ?

No

No

No, I want to create Line Failure Incident

Reports

Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls Questionnaire

1. Incident Description:

2. When did failure occurr?

3. Details of Failure:

JOINT INDUSTRY PROJECT: FPS MOORING INTEG

INCIDENT REPORT EXAMPLE

Failure of the retaining bolts on a w ire open socket which

allowed the pin to come free and the mooring line to part.

Two to three years after installation.

On a turret moored moored floating storage unit the connection

detail between the chain and the wire consisted of a wire end

socket, a triplate and a D type shackle connecting to the

grounded chain. The wire open socket was connected to the

triplate by a round connecting pin that was held in place by an

end plate secured to the socket by 3 bolts aorund its

cicumference ands to the pin by three bolts in a line. During a

subsea survey it was found that the end plate had dropped off

and the pin dropped out. It was also noted that the end plate

bolts had failed or backed off on a number of the other socket

connections althouh the pins had not yet dropped out.

4. Probable Incident Cause (if known) including weather conditions at the time of failure

5. Incident Consequences:

6. How was the failure detected?

The connection was inb the sea bed working section of the

catenary (the thrash zone) and as the wire socket was repeatedly

picked up and set down there was a large relative motion

between the socket and thge heavier triplate and grounded chain

section that typically remains on the sea-bed. It is thought that

this introduced a large torsional/friction load between the pin

anbd the body of the socket that could not be accommodated by

the end plate retaining bolts and these failed allowing the end

plate to drop off and the pin to fall out. There had also been a

failure to insulate properly the wire section from the chain

section and the cathodic protection on the wire weas drained

down by the grounded chain section resaulting in a corrosive

environment that might have contributed to the failure.

Temporarily restricted offloading operations plus repair costs.

Subsea ROV survey

7. Remedial action?

8. Mean time to repair?

Replacement of pins, modification to the retaining bolts and re-

instatement of the cathodic protection.

Initial repair approximately 12 weeks, total refurbishment several

months,

A4163-01 280

25 APPENDIX C – 2005 OTC JIP PAPER

Copyright 2005, Offshore Technology Conference

This paper was prepared for presentation at the 2005 Offshore Technology Conference held in Houston, TX, U.S.A., 2–5 May 2005.

This paper was selected for presentation by an OTC Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Papers presented at OTC are subject to publication review by Sponsor Society Committees of the Offshore Technology Conference. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, OTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract

Over the last two years Noble Denton has been undertaking a Joint Industry Project (JIP) to investigate how to improve the integrity of the moorings used by Floating Production Systems (FPSs). The JIP has surveyed the world wide performance of all types of FPS mooring systems including FPSOs, semi submersible production units and Spars. Wide ranging support from 23 sponsoring organizations including operators, floating production contractors, regulatory authorities, equipment suppliers and inspection companies has enabled access to a significant pool of data.

This paper utilizes the JIP data to discuss the following:

• Causes of system degradation

• Consequences of mooring failure

• Key areas to check on a mooring system

• Fatigue implications of friction induced bending

• Options for in-water inspection

• The importance of connector design

• Methods to detect line failure

• Contingency planning

A few pioneering floating production units have now been on station for many years. Review of inspection data from these units shows that selective repair may be needed to maintain the design specification right up to the end of the operational life. It has been found that wear can be faster on leeside, as opposed to windward lines and that certain weighted chain designs are susceptible to damage.

The likelihood of line failure and the implications need to be better appreciated. Following failure, it may well take several months to implement a full repair, due to a lack of spares/procedures and possible non-availability of suitable vessels. However, it has been found that carefully planned and coordinated inspection operations can detect potential issues early on before more serious deterioration takes place. In general, mooring monitoring/instrumentation and access for in-water inspection seem not to be as advanced as might be expected for a system which is safety critical. Hence good practice recommendations are included which can be applied to both existing and planned future units.

Introduction

Unlike trading ships, Floating Production Systems (FPS’s), stay at fixed positions year after year without regular dry docking for inspection and repair. Since they cannot move off station, they must withstand whatever weather is thrown at them. Hence at times, depending on their location, their mooring systems need to withstand high storm loadings. Typically during design, mooring systems for harsh environments do not have much reserve capacity above what is required to withstand survival conditions. Therefore deterioration of the lines over time can increase the likelihood of single or multiple line failures. Multiple line failure could conceivably result in a FPS breaking away from the moorings and freely drifting in the middle of an oil field.

The Mooring Integrity JIP has been concerned with assessing how mooring systems have performed in the field to identify the level of degradation which has taken place. Hence the project has looked at FPSOs, Semi submersible production units and Spars through out the world. The key objectives have been:

• To feedback operational and inspection experience to the industry and to mooring designers

• To publicize how hard moorings work, their importance and potential vulnerability

• To disseminate best practice guidance

OTC 17499

Floating Production Mooring Integrity JIP – Key FindingsMartin G. Brown, Noble Denton Europe Limited

Tony D. Hall, Welaptega Marine Limited

Douglas G. Marr, Balmoral Marine Limited

Max English, U.K. Health and Safety Executive Richard O. Snell, B.P. Exploration

2 [OTC 17499]

From the survey it has become apparent that certain problems have occurred and thus the JIP wishes to publicise these so that they can be taken account of during inspection of existing units and during the design of future units. Taking due account of past experience is particularly important when a design premise or specification is being developed for a new project.

International Survey

Significant effort was made to try and ensure that the international survey was as simple and straight forward as possible for respondents. To this end a custom designed spreadsheet based questionnaire with drop down boxes was developed. This spreadsheet was partially completed by Noble Denton, using information in the public domain, before being emailed out for checking and final completion.

As well as the questionnaire face to face interviews were carried out with key personnel from different areas of the industry. Conference papers, in-house data and journals were also consulted. Response to the questionnaire was reasonable, but could have been better particularly for non North Sea regions. This perhaps gives some indication of the priority level that at present seems to be associated with mooring systems. Initially it was believed that offshore based staff would be able to complete the questionnaires. However, it became apparent that in some assets there is little in-depth knowledge about the make up and history of their mooring systems. Overall though, in summary, good data was obtained, but not on as many units as had been originally planned.

Degradation Mechanisms

Intrinsically mooring lines present a fairly simple system for keeping a floating object on station. However, experience from the field has shown that mooring is in fact a particularly difficult dynamic problem. Figure 1 illustrates a number of the degradation mechanisms which a mooring system will be exposed to every day of its operational life. Inevitably the performance of the system will decrease over time. Despite this, at the end of the field life, which in certain circumstances could be in excess of 20 years, the mooring system normally still needs to be capable of withstanding 100 year return period storm conditions. This represents a stern test for any 20 year old mechanical system. It is also logical that the longer a mooring system is out there, the higher is the probability that it will encounter extreme weather conditions.

Many of the mooring issues mentioned in this paper refer to chain. This is because chain is normally selected at the two most challenging locations, namely the vessel interface and the sea-bed touch down. Since the loading regime is severe degradation may sometimes occur. However, experience over the years has shown that using wire in these areas does not give a true long term solution. The same would almost certainly apply to the use of fibre ropes.

Figure 1 –Mooring degradation and the key areas to inspect

Historical Incidents

Given these degradation mechanisms a search was made of historical records to see what lessons could be learnt from past incidents. This search identified the following incidents which could have implications for present day systems, although particularly for the SALM the failure mechanism was unique to the system concerned:

• Argyll Transworld 58 production semi, complete break away in 1981

• Fulmar FSU, complete break away in 1988 from the SALM (Single Anchor Leg Mooring).

• A series of semi sub multiple line failures in the storms of Oct. 1991 and January 1992, see ref 5.

• Petrojarl 1, 1994, 2 lines failed at the same time when hit by a 20 to 25m wave 10º off port bow.

The TW58 and the Fulmar 210,658dwt storage tanker both broke away after 6 years and 7 years on station. These durations tie in surprisingly well with the failure statistics reported later on. The TW58 was designed to and had disconnected its risers before breakaway, but it was still free drifting for 1.5 days in the North Sea before it was possible to attach a tow line to it. The Fulmar FSU did not have propulsion and was drifting for 5 hours before tow lines could be attached.

Reference 5 is informative since it gives an idea of how much damage can be inflicted by unusually severe, but not freak, storms. The Petrojarl incident is significant since it shows that if there is a common degradation mechanism multiple line failure may occur virtually at the same time. In this case redesign of the chain guides and up-rating the chain resolved the particular problem.

Consequences of Mooring Failure

Environmental Impact

The design premise of the majority of FPSs is that they should be able to withstand a single mooring line failure without the resulting increased vessel offset causing damage to the risers. Multiple line failure is only likely to occur if a failure has gone un-detected (see later) or if there is general degradation which

Bending & Tension

Highest Tensions

Corrosion

Impact & Abrasion

Wear & fatigue

[OTC 17499] 3

is affecting all lines in a particular quadrant to approximately the same extent, see Figure 2.

Figure 2 – Possible Line Failure and Repair Scenarios

In the unlikely event of multiple mooring line failure causing rupture of one or more risers, the extent of hydrocarbon release will be strongly dependant upon whether or not the risers are still pressurized. Typically it is assumed that mooring line failure will be progressive and thus there will be sufficient time to shut down production and depressurize the risers, before the resulting increased vessel offset causes damage. However, the multiple mooring line failure which occurred on Petrojarl 1, when hit by a shock-inducing steep wave, shows that loss of position keeping on a non DP assisted vessel could occur remarkably quickly. This could possibly be in wave heights below survival criteria. Hence, it is recommended that on-board emergency procedures should identify what action should be taken in case of single or multiple riser rupture while the risers are still pressurized.

If the risers are depressurized when rupture occurs, the extent of possible hydrocarbon release ranges from 100m3 to 2,500m3. This depends on field specific architecture such as the number of risers and the step out distance of the flowlines.

Business Interruption Impact

The business interruption cost of a single mooring line failure is not insignificant when the cost of anchor handling tugs, ROV or dive support vessels, new components and deferred production is taken into account. For example the following costs have been estimated for two typical cases.

• £2M for a 50,000 bpd N. Sea FPSO

• £10M for a 250,000 bpd W. African FPSO

Multiple line failure which does not cause breakaway, but results in shut down for an extended period, would cost much more than the figures outlined above.

Causes of System Degradation - Case Studies Corrosion and Wear – North Sea Production Semi

A fascinating insight into the possible future performance of modern FPSs is provided by a purpose designed new build North Sea production unit which has been in continuous

operation for coming up to 20 years. During this time the FPS has experienced three mooring failures, plus significant defects have been found on two other lines during inspection. Interestingly all three line failures have been on lines which are defined as leeside lines based on prevailing weather conditions (see Figure 3). Leeside lines are in general under less tension and this seems to result in greater relative rotation/ motion between chain links and thus more wear. On first thought it might be expected that greater wear would be expected on the more heavily loaded windward lines. However, a bar tight line will in fact see less relative rotation between links than a slacker line subject to the same movement of the surface platform.

Figure 3 – Illustration of Windward and Leeward Lines

On this unit the failures have typically been on chain which at the no load equilibrium position is somewhat above the touch down point. Hence, in-water inspection during calm weather should make sure that this area is carefully inspected. Accelerated degradation in this area is highlighted by a more recent ROV inspection which has revealed that a studded chain has shed studs – see Figure 5. This is interesting, since it proves that studded chains can lose studs in situ rather than just during the relatively harsh handling that chain receives during a recovery operation by an anchor handling tug.

Figure 4 shows a recovered link which was close to the link which failed in service. The failed link could not be found on the sea-bed. On the photograph it is interesting to note that the area of maximum wear is not at the point of contact between two links under tension, otherwise known as the inter grip area. Instead it is part way down the inner face of one side of the link. Damage was also noted on the crowns of other links. This suggests that some form of dynamic impact/grinding action is occurring which is wearing down the links. Significant inter link motion is thought to have been a factor contributing to the shackle pin failure illustrated on Figure 9.

Losing material in this area is significant, since a finite elements analysis of a link will confirm that this is a highly stressed area. This is one of the reasons why it is recommended that tests should be undertaken to determine the actual break strength of worn mooring components.

4 [OTC 17499]

Figure 4 – Example of Wear and Corrosion on a Chain Link from the Sea-bed Touch Down Zone

Based on the original nominal diameter of this chain, which it is appreciated can vary; the combined wear and corrosion rate over its years of use has been estimated to be 0.6mm/year.This wear has occurred around the chain touch down area at the sea-bed, otherwise known as the thrash zone. 0.6mm/year of wear/corrosion is 50% higher than the maximum values found in API’s RP2SK and DNV’s OSE301 (refs. 3 and 4). It is interesting to note that a corrosion rate of 0.3 to 0.88mm/year for uncoated steel has been quoted on a long-term inshore project where sulphate reducing bacteria (SRB) induced corrosion might be experienced.

Figure 5 – In water inspection showing a Studded Chain which has lost its Stud in situ

If the combined wear and corrosion rate is higher than that specified in mooring design codes this may well have significant implications for the true long term integrity of FPS moorings. It is appreciated that the wear rate reported here may well not be appropriate for all regions and platform types/system pre-tensions. However, the fact that this level of wear/corrosion has been experienced does highlight the importance of obtaining more data on wear/corrosion for other long-term moored units. The options for in-water inspection are discussed later on. There are, however, some limitations and hence it would be highly desirable if comprehensive inspection, including dimension checking, could be

undertaken of mooring components whenever a FPS comes off station or has repairs done to its moorings.

Mooring line Configuration at the Vessel Interface

The design of the vessel interface needs to minimize the potential for wear, corrosion or other forms of degradation. However, experience is demonstrating that this is not always being achieved. This is discussed below. The key points are relevant to mooring systems in general, not just to one particular type.

Although there are a number of different turret mooring system designs, including both internal and external turrets, it is possible to categorize them as follows:

a) Non adjustable permanently locked off chains at the turret base

b) Adjustable chains which come up through the turret and are stored in a chain locker.

On Type a) systems the line tensions are not intended to be changed at any time throughout the field life. Type b) systems use a wildcat at the base of the turret similar to that found on a drilling rig running chains. Type b) FPSOs typically adjust their lines lengths and tensions either annually or even monthly. On some designs of spread-moored FPSOs the line lengths are also not intended to be adjusted and the required equipment for adjustment may not normally be present.

If the line lengths are never adjusted during the field life this means that the same links in the thrash zone and at the turret interface will need to withstand the majority of the degradation. In addition, inspecting lines in situ is more difficult, since the chain is relatively inaccessible inside the trumpet/chain stopper. It is also much more difficult with such designs to pick up the chain off the sea-bed to make it more accessible for in water inspection.

Being able to adjust line lengths can introduce its own perils. During a regular line tension adjustment operation on one North Sea FPSO there was a failure of the lifting and locking mechanism. This was partly due to a late change in chain size and the fact that the tolerances of forged chain links had not been properly taken account of. The failure resulted in the complete line being whipped out of the turret and falling down through the water column to the sea bed. Fortunately no one was hurt and there was no damage to subsea architecture. Modifications to the lifting and locking mechanisms should prevent another incident of this type occurring. It is worth noting that line run-outs are far from unknown on semi-submersible drilling rigs. This incident highlights the importance of reviewing all similar mechanical systems to check that, during the course of a long period of operation, chain/stopper wear or link dimensional variation may not jeopardize the integrity of the mechanism.

Wear at Trumpet Welds – Internal and External Turrets

On two type a) turret configurations wear has been experienced where the chains have been rubbing against the weld beads where the bell mouth joins with the parallel

Localised Wear

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trumpet section (see Figure 6). This was first experienced on an early S.E. Asian external turret moored FPSO and more recently on an internal turret moored N. Sea FPSO. For the internal turret a slight shadow was seen on one of the chains during the annual workclass ROV chain inspection programme. To check out this anomaly a test tank mock up of the chain and trumpet assembly was built so that the capability of using a football sized micro-ROV to get in close to the bell mouth could be evaluated. This concept proved to be successful as can be seen from the photograph taken by a micro-ROV in the field, see Figure 7.

Figure 6 - Test Tank Mock-Up of Micro-ROV inspection of Chain Emerging from Turret “Trumpet”

In the case of the external turret, in air access was such that it was possible to shroud the chains where they were rubbing against the weld beads with a replaceable material (ultra high molecular weight polyethylene sheeting). However, for the submerged trumpets on the North Sea unit a more long-term repair was needed which involved changing out the worn chain at the trumpet with larger diameter chain with a specially applied hardened coating (cobalt chromium) to reduce the severity of any future wear. A special connector (see Figure 15) was developed to allow the new chain to be connected up to standard common link chain. This approach avoided disturbing the wire section of the mooring line on the sea-bed, which is relatively susceptible to damage (birdcage). The original system designer was included in the review process for the repair operation. This represents good practice which, where possible, it is recommended should be followed for any future FPS mooring repair operations.

On type a) systems the trumpets are typically pivoted about a single axis so as to minimize chain rotation and wear. Since the rotation is only about one axis and the trumpets are arranged around an approximate circle, the pivoting action cannot eliminate chain rotation for all the lines at the same time. Thus, to minimize wear over a long field life, there may be arguments for selecting a design which can pivot about two axes, although this would be mechanically more complicated.

Figure 7 - Micro-ROV Photograph of Chain Wear Notches where Chain Emerges at the Trumpet Bell Mouth

Trumpets or guides are included on type a) FPSO designs to help guide the chain into the chain stopper. The trumpets themselves may include “angle iron” guides to ensure that the chain is in the right orientation when it enters the chain stopper. Once the chains are tensioned the trumpets have no real purpose unless they are required in the future for a new chain pull in operation. Interestingly, the pivoting chain stopper design which was adopted for the Brent Spar buoy did not include trumpets to help guide in the chain. The Brent Spar mooring was a successful design with a 19 year operational life and minimum wear on the chains at the stoppers when they were examined when the Spar was cut up in Norway. There was one failure but this was at a kenter connecting link. Such a failure is not surprising, since standard kenters are known to have low fatigue lives. There are, fortunately, now new designs of kenters with improved fatigue lives, but these still do not at present have classification society approval for long-term mooring.

It is significant to note that the chain stopper on type a) designs is typically inboard of the pivot point. This means that the trumpet assembly does not automatically follow the motion of the chain. In fact it is contact between the chain and the outer face of the bell mouth which causes the trumpet to rotate. It is this contact, plus an associated sliding/sawing action, which seems to have led to the chain notches shown on Figure 7.

Intrinsically there does not seem to be any reason why the chain stopper should be inboard of the pivot point. If it is outboard of the pivot point movement of the chain should cause movement of the trumpet without the need for chain contact with the bell mouth. This type of arrangement has been adopted on some more recent spread-moored FPSOs.

For chain stoppers which are inboard of the pivot points it would appear that long trumpets are not helpful after the completion of the installation process. Thus it is recommended that careful checks should be made on any units which fit this category.

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In general achieving compatible chain surface hardness is important for long term integrity, since it affects wear. Unfortunately, at present chain hardness and wear do not seem to be evaluated in any detail. These factors should be taken account of during detailed design, but more work is needed on this area before it becomes part of the standard design process.

Friction Induced Bending

When a chain is under tension there will be friction and local yielding between the links which will inhibit inter link rotation. It is found that the higher the tension in the line, the greater the frictional forces. This friction can result in out of plane bending on individual links, see Figure 8.

Figure 8 - Illustration of Friction Induced Bending

Thus out of plane bending tends to become more of an issue as water depths and line pre-tensions increase. Over time cyclical out of plane loading can cause fatigue damage. This has been illustrated by a number of fatigue failures which have occurred on a taut moored CALM buoy off West Africa.

Historically, mooring line fatigue has not been evaluated, partly due to the complexity, since MODUs work in different geographical locations areas on relatively short assignments. Today, for long term moored units, a fatigue assessment is typically carried out (refs. 3, 4 and 6). Such an analysis is normally in terms of tension loading cycles; it does not consider the combined effects of bending and tension. For long term moored units it is clear that friction induced bending fatigue should be evaluated. This is particularly important for deep water taut moored systems, but will still have some relevance for units in more moderate water depths. Physical testing has been undertaken to evaluate suitable friction coefficients for chain subject to out of plane bending9.

In field experience has shown that the orientation of the links where they emerge from the bell mouth can significantly affect fatigue life. Improved fatigue life can be obtained if the “dynamic link” just outboard of the bell mouth is in a vertical plane. In other words the oval face of the link is at 90º to the sea surface.

Excursion Limiting Weighted Chain and Mid Line Buoys

From a mooring design perspective increasing the chain weight for a section of mooring line in the thrash zone can be a beneficial solution to reduce vessel offsets. This tends to be particularly applicable for moderate water depths in harsh

environments, which represents a particularly taxing mooring problem. There are a number of ways in which this can be achieved. However, from the international survey it is clear that great care is needed to select a robust system if such an approach is adopted.

One way of increasing the chain weight, is to hang off short chain lengths from the main mooring chain. This was the solution adopted on one harsh environment FPSO. However, Figure 9 illustrates the damage that has been caused to one of the pins. It is believed that this damage may well have been caused by a dynamic pinching/grinding action of adjacent links.

Figure 9 – Photograph of a Partial Failure of a Hang-Off Shackle Pin

Another possible approach to increasing the line weight over a certain section is to attach clump weights to the chains. illustrates half of a clump weight from a FPSO mooring line which utilized such a system. In this instance it can be seen that the bolts which kept the two half shells together have failed and the clump weight has thus split open. Again the dynamic loading of the line is thought to have led to the failure of the restraining bolts.

Figure 10 - Chain Clump which has become detached – only one half of the Clump Weight Visible

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Other systems for increasing chain weight locally include a parallel chain system with triplates or using a larger chain size. Both of these systems appear to have worked successfully, although there is a need for careful design of connectors. This is because enhanced wear may be experienced due to an increased rotation resulting from a change in the weight per metre at the connectors.

An alternative way of reducing FPS excursions due to mean wind, current and wave drift forces is to add buoys on to the mooring lines. However, problems have been experienced on one FPSO with the buoys becoming disconnected from the lines over time. Interestingly this seems to have been on leeward lines, which indicates that that the increased motion of the less tensioned lines may be contributing to the problem.

Connector Failure – Unintended Line Disconnection

Careful detailed design of long term mooring connectors is vital to ensure that they are fit for purpose. Figure 11 illustrates an unintended line disconnection on a FSU. This socket was at the transition from wire rope to chain. Hence, there was a weight per metre discontinuity which resulted in extra rotation at the connector. In this instance the socket pin was restrained from rotating by relatively small bolts. The pin wanted to rotate and it eventually sheared the bolts on the end cap which allowed the whole pin to work loose. It is interesting to note the size of the locking-pins which make up the double locking system on the purpose designed connector shown on Figure 15. The substantial size of these pins was based on hand calculations utilizing the expected line loads and an estimated friction factor. In the case of the unintended disconnection, at times, depending on vessel offset, the connectors would have been in the thrash zone. They would have experienced repeated lift up/set down contact with the sea bed.

Figure 11 - Unintended Line Disconnection due to the Failure of a Socket Restraining Mechanism

“Dog Leg” or Wavy Mooring Lines on the Seabed

During mooring line installation it is important that all lines should be laid straight from the anchor to the fairlead at the no load equilibrium position. This requirement should be emphasized in the installation procedures and reflected in any tug specifications. If “dog legs” or wavy lines do end up being present and they are pulled out by storm loading, this can lead to unbalanced mooring line tensions. In other words a system which was balanced originally with the “dog legs” may no longer be so. If one line takes more of the load coming in from a particular quadrant it is more likely to fail. If this originally taut line fails, the FPS may exceed its allowable riser offset limit if the remaining lines are too slack. At present non straight mooring lines have been noted on two North Sea FPSOs. On these units the initial pre-tensioning operation and the storm loadings which have been experienced have been insufficient to overcome the friction of the lines in the sea-bed mud. But to date, these FPSOs have not yet experienced storm line loadings as severe as the maximum loadings evaluated during the mooring design process. It will be interesting to see if, over the respective field lives, the “dog legs”/wavy lines are pulled straight or not and this should be monitored during annual ROV surveys. If straightening does occur the implications for mooring behaviour should be fully evaluated.

Unbalanced Set-Up Pretensions

On a long-term moored semi-submersible FPS, offshore personnel doubted the tension readouts on their mooring line winches, since damage was occurring to the wires on the winch drums. In addition, when grappling for certain components on the mooring line they were not found at the expected depth.

Therefore, in calm weather, an underwater ROV survey was undertaken of the triplate connectors to obtain their X, Y and Z co-ordinates. From these positions and knowing the submerged weight of the line, it was possible to perform a catenary calculation to estimate the actual line tension. These tensions can then be compared to the winch tension readouts. This process showed that in the worst instance the calculated and the measured tensions were out by 160% !

Tension meters fitted to the base of pull in winches/windlasses can give a poor estimate of the tension in mooring lines, even if properly calibrated, since the amount of friction in the sheaves/fairleads is variable and difficult to quantify. In addition there is a possibility of full or partial seizure of the submerged lower sheaves or wildcats. To check this out, during a period of good weather, a carefully controlled Line Pay-Out/Pull-In test was undertaken. In this test each line was paid out in 2m increments and the line tensions were recorded. The lines were then pulled in again the same amount and the winch tensions noted. If this test is undertaken relatively quickly in calm weather conditions it would be expected that the same line tension would be obtained for the same line payouts. In actual fact this did not prove to be the case for all mooring lines, see for example Figure 12.

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Line No11

185.0

186.0

187.0

188.0

189.0

190.0

191.0

192.0

193.0

194.0

195.0

0.0 20.0 40.0 60.0 80.0 100.0 120.0

Tension (te)

Wir

e p

ay

ou

t (m

)

Figure 12 – Example of a Pay-Out/Pull-In Test for a Seized Sub Sea Sheave

Historically semi-sub drilling units have been subject to relatively frequent mooring line failures. The work reported in this section shows that it is possible for a carefully set up Rig to have a seriously unbalanced mooring pattern which the Operators might not be aware of. Further information can be found in ref. 5. It is hoped that Pay-Out/Pull-In tests can be undertaken for other semis to determine how wide ranging or otherwise this occurrence could be.

For long-term moored units it is recommended that a ROV should double check the line tension balance by measuring X, Y and Z co-ordinates of known points on the line or the touch down points. This should be done in good conditions and then a back calculation can be done of the line tensions.

Recent Multiple Line Failure Incidents

Unfortunately serious mooring incidents continue to occur. For example, a December 2004 North Sea storm resulted in a drilling rig losing two of its eight anchor chains. The resulting excessive excursions ruptured the drilling riser.

During hurricane Ivan five MODUs broke free from their moorings and were set adrift. One of the units was a fifth generation rig. Fortunately, as far as can be determined, Ivan did not cause damage to the mooring systems on any of the long term moored FPSs in the Gulf of Mexico.

Indicative Failure Statistics

Based on the limited response obtained during the international survey, it is quite possible that only a fraction of the total number of mooring incidents which have occurred outside the North Sea have been reported. In the North Sea there are statutory requirements for mooring incidents to be

reported to the UK Health and Safety Executive (HSE). Although the North Sea is a hostile climate, units intended for use here are in general designed to a high standard. In addition, a number of units in the North Sea have been around long enough for age related problems to start making an appearance. It thus seems prudent to consider official statistics for this region to be a reasonable indicator of the likelihood of mooring line failure. Based on reference 2 for the period 1980 to 2001 it is reported that a drilling semi-submersible might expect to experience a mooring failure (i.e. anchor dragging, breaking of mooring lines, loss of anchor(s), winch failures) of once every 4.7 operating years, once every 9 years for a production semi submersible and once every 8.8 years for a FPSO. Thus it can be seen that although the failure probability for production units is approximately half that of a semi-submersible drilling unit, the statistics indicate that it would not be totally unexpected for the crew on a FPS to expect a mooring line failure at sometime during a field life which exceeds 9 years. Exactly how these statistics can be related to milder environments is difficult to quantify at present.

Good Practice Recommendations

In Air-Inspection

Mobile Offshore Drilling Units (MODUs) need to recover their mooring lines and anchors on a regular basis when they move from one location to another. This provides periodic opportunities to undertake in-air mooring line inspection when the vessel is in sheltered water. Alternatively a spare line may be bought or rented which can be swapped out with one of the existing lines while the original line is taken to the shore for inspection and possible refurbishment.

FPSs spend much longer on location than MODUs. Hence, their mooring lines are normally only recovered when the FPS moves off location. It is possible to recover mooring lines part way through a field life but this has two disadvantages, namely:

1. The lines may be damaged either during recovery or re-installation

2. The whole operation is expensive since the services of anchor handling and possibly heading control tugs will be required for a number of days.

Given that even in-air inspection will not necessarily detect all possible cracks and defects which may be present; there is an understandable interest among operators to undertake in-water inspection. However, there will still be times when anomalies are identified which can only be resolved with true confidence by undertaking in-air inspection. One definite advantage of in water inspection is that it is easy to identify which parts of the chain have been in the thrash zone and at the fairlead. This is more difficult to determine for long lengths of chain lying on a quayside.

In-Water Inspection

To date chain mooring components have been the subject of the greatest effort to develop in-water inspection methods.

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This is because they are typically used in the sections of moorings subject to the greatest deteriorative forces, particularly at the seabed touchdown (thrash zone) and at the vessel interface. Both windward and leeward lines should be inspected, but a particular check for wear should be undertaken on the leeward lines, see Figure 3. Care is needed when inspecting the touchdown zone, since potential hazards such as rocks or debris on the sea-bed can cause mooring line abrasion. These hazards may be partially obscured by the sea bed/mooring line and thus good visibility with powerful lighting is required.

In-Water Chain Measurement

A number of in water mooring chain measurement systems have been developed with varying success, ranging from simple diver-deployed manual calipers to a prototype stand-alone robotic system and ROV deployed systems.

Diver inspections are not a favoured option. Mooring chains are highly dynamic and therefore are potentially dangerous when divers are in close proximity. Also diver inspection has proven to generate inconsistent results and has inherent depth limitations, for example, when checking the thrash zone.

A stand-alone robotic system has been developed, but so far this has proven too large and cumbersome for practical offshore operations. In addition, it does not appear able to inspect the vital seabed touchdown or get in close to the fairleads.

ROV-deployed systems include both mechanical caliper and ‘optical caliper’ systems. Mechanical calipers have met with limited success, primarily because during deployment onto chain they have the potential to be knocked out of ‘true’ and consequently may well have to be recalibrated between successive measurements.

The most established ROV-deployable chain measurement system is effectively an ‘optical caliper’7, comprised of multiple high resolution video cameras and lights on deployment frame, which is equipped with scale bars in pre-assigned orientations and at set distances from each other and the cameras (Figure 13). The system measures the chain parameters by calibrating from the tool scale bars and resolving dimensions and optical distortions using offline image analysis software.

This type of system has no depth limitation, requires no physical recalibration and can be configured to measure not only chain components at the seabed, but also in difficult to access regions such as the vessel interface. It can also be configured to measure other types of mooring ‘jewelry’ such as connectors, shackles and kenter links.

The ‘optical caliper’ chain measurement technology is used extensively by offshore operators and is accepted by a number of offshore certification authorities. In this respect in at least one instance it has been used as the basis for an extension of

the prescribed recertification period for an in-service FPS facility.

Figure 13 - Illustration of ROV deployed ‘optical caliper’ measurement system

7

Loose Stud Detection

In studded chain, loose studs have been implicated in crack propagation and fatigue. Accordingly studded chain inspection and recertification protocols require the assessment of the numbers of loose studs and degree of ‘looseness.’ However, there is no consensual industry opinion with respect to loose stud reject criteria. Traditionally chains have had to be recovered for detailed loose stud determinations and have relied on a manual test, either moving the stud by hand or using a hammer to hit the studs. The resulting resonance (a ‘ping’ or ‘thud’) is used to assess whether a stud is loose or not.

Recently an ROV-deployable loose stud detection system has become commercially available7. The system uses an electronically activated hammer to impact the stud and uses a hydrophone and a micro-accelerometer as sensors. A software program is used to distinguish between ‘loose’ and ‘tight’ responses. Cross checks can be carried out in that very loose studs can be detected using a ROV manipulator or a ROV deployed high pressure water jet.

Component Condition Assessment

As well as chain dimension checking it is also important to assess link integrity and condition. The overall, or general, condition of mooring components often gives insights into the types of deteriorative processes that are at play. For example surface pitting may be indicative of pitting corrosion, ‘scalloping’ or indentations of wear, fretting corrosion, or ‘anvil’ flattening, and unusual geometry may indicate friction bending, or plastic deformation (e.g. stretch).

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Underwater visual condition assessment by ROV is particularly difficult because of the inherent ‘flatness’ of video images from standard 2D inspection cameras. With 2D cameras it is very difficult to distinguish whether a visual artifact on a surface is merely a mark, or a region from which material has been lost (e.g. a pit).

The shortcomings of 2D video can be addressed by using 3D visualization, a long-time goal in the underwater inspection sector. Over the last two decades a number of 3D visualization systems have been implemented but, until recently, with limited success due to problems with user comfort and impractical and cumbersome viewing systems.

Advances in 3D camera design and the development of user-friendly viewing systems have led to the introduction of a new generation of 3D video systems7. These cameras come in a range of configurations, sizes and depth ranges and have proven very effective for the assessment of the surface condition and general geometry of mooring components. Improvements have also been made in video asset management, so that it is now easier to access data without trawling through hours and hours of video footage7.

Marine Growth Removal

A key challenge of conducting in-water inspection is getting access to the component(s) to be inspected. Materials which have been in sea water for extended periods accumulate varying levels of marine growth which can be heavy, depending on geography, water depth and season10, (see Figure 14). This growth needs to be removed so that the underlying mooring components can be inspected.

Figure 14 – Illustration of Marine Growth on Long Term Deployed Chain

Cleaning options include manual brushing by divers, rotary brushing with wire or synthetic fibre brushes and ROV deployed high-pressure water or grit-entrained high pressure water. Each system has its own pros and cons.

Once marine growth is removed it is possible to conduct various levels of inspection including general visual

inspection, dimensional measurement and assessment of mechanical fitness. Unfortunately cleaning off marine growth and scaling by high pressure water jetting may accelerate corrosion by exposing fresh steel to the corrosive effects of salt water. At present there are currently no in-water inspection methods for mooring components that do not require the prior removal of marine growth. This represents a technology gap which warrants further investigation.

The time required to remove marine growth depends largely on the cleaning option chosen and in light of the cost of ROV vessels, can be a substantial component of the cost of an inspection program. Consequently it is essential that the planning stage of mooring inspection campaigns should consider the most suitable cleaning options for the expected conditions.

Line Status Monitoring and Failure Detection

Given the safety critical nature of mooring lines one might imagine that they would be heavily instrumented with automatic alarms which would go off in case of line failure. In practice many FPSs are not provided with such instrumentation/alarms – see indicative statistics below. On type a) turrets in which the chains are permanently locked off under the hull it is particularly difficult to monitor these lines in a reliable manner. For example, how do you readily distinguish between mooring line and instrumentation failure, without direct intervention ?

Another factor which makes it difficult to be 100% sure of the condition of a set of mooring lines is that line breaks do occur along the sea-bed or in the thrash zone. If this happens the line will drag through the mud until the friction exerted by the soil surrounding the chain matches the tension in the chain at its sea bed touchdown point. Experience has shown that high line pulls are required to drag large diameter chain through the sea-bed.

The following indicative statistics, based on data from the majority of North Sea based FPSOs, give an indication that instrumentation is not as prevalent as might be expected for such a heavily regulated region:

• 50% of units cannot adjust line lengths,

• 50% of units cannot monitor line tensions in real time,

• 33% of units cannot measure offsets from the no-load equilibrium position,

• 78% of units do not have line failure alarms,

• 67% of units do not have mooring line spares available.

The present position of the U.K. Health and Safety Executive is that Operators should have in place suitable performance standards for the time taken to detect a mooring line failure. This is particularly important as common mode failure mechanisms such as fatigue or wear are likely to be prevalent on more than one mooring line and early detection of a line

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failure with appropriate mitigation strategies could prevent system failure. Depending on the inherent redundancy of the mooring spread, the time taken to detect a failure could range from virtually instantaneous detection to detection in a matter of days. It is clearly not appropriate to rely on annual ROV inspection to check if a mooring line has failed. Monitoring the excursion of a FPS, particularly using differential GPS is inexpensive and will provide mariners with a feel for the mooring integrity. But without real time monitoring of the environment it is unlikely to indicate a line failure in anything but storm conditions, unless in deep water. Satellite drift is also a potential factor affecting the reliability of offset monitoring.

New methodologies to detect a mooring line failure typically feature acoustic transponders deployed through the turret, attached to the hull of the FPSO, or installed on the seabed to provide an indication of the catenary’s profile. Such systems should be trialed in the near future in the North Sea. Another option may be a response learning system which takes into account the expected performance in measured weather conditions. The response will be different if a line fails due to a resulting change in the mooring system stiffness. Such an approach requires further development work. But if the concept proves successful this could prove to be a relatively simple and inexpensive retrofit.

Contingency Planning - Spares and Procedures

Based on the indicative failure statistics reported earlier it is quite conceivable that a FPS may lose a line during its operational life. There is likely to be a several month lead time to procure components such as large diameter chain, wire/fibre rope or purpose built connectors, see for example Figure 15. Hence, to minimize FPS safety and business exposure in case of line failure, it is believed to be well worthwhile to have spare lines, connectors and procedures available for immediate use if required. For deep water projects the procedures should ideally be developed which are based on a generic anchor handling vessel rather than a high specification installation vessel. Installation/construction vessels are unlikely to be readily available at short notice and tend to be expensive.

If a line does fail and no spares are available it may be possible to “mix and match” making use of available equipment from the established marine supply and rental companies. However, the impact of introducing non standard elements into a mooring system is best considered before a failure occurs. Long term mooring (LTM) shackles should ideally be used as the connectors, but virtually any type of shackle including alloy shackles would do in the short term. Repairs of this nature should give time for the procurement of the correct equipment, which may take around six months depending on industry demand. Because the mooring system has been damaged and then modified, it may be necessary to obtain concessions from the relevant Classification Society/Independent Competent Person (ICP). A reduced operating envelope may have to be accepted during the period that the temporary repairs are effective.

Figure 15 – Purpose designed connector for common link to common link chain allowing some compliance in two planes

Maximum Sea State for Continued Production Following

Line Failure

Once a mooring line fails it is believed to be no longer appropriate to apply the lower damaged system line safety factors. This is because, in most instances, the reason for the line failure will not be immediately apparent. Thus with the increase in loading in the remaining lines there is an increased chance of a further line failure. Hence, it is recommended that the higher intact system line safety factors should be applied. Meeting the intact line safety factors with a degraded system will typically result in a reduction of the maximum allowable sea state. Data on the reduction in the maximum operational sea state in case of line failure should be readily available on all units. The international survey indicates at the present time this data is not generally available either with the designers or on the units offshore.

Conclusions

Moorings on FPSs are category 1 safety critical systems. Multiple mooring line failure could put lives at risk both on the drifting unit and on surrounding installations. There is also a potential pollution risk. Research to date indicates that there is an imbalance between the critical nature of mooring systems and the attention which they receive. On many FPSs there is an important need to improve the knowledge base of offshore personnel on the intricacies of their mooring systems and their potential vulnerability. This will help to ensure that mooring systems receive the amount of attention they deserve, particularly during inspection operations.

The interface between the surface vessel and the mooring line requires particular attention for all types of FPS. Carefully planned innovative inspection making use of all possible tools has been demonstrated to be able to detect problems relatively early on before they become a potential source of failure. The use of micro-ROVs to gain access to restricted areas not accessible by conventional ROVs and divers has been part of the key to this success. The inspection which has been

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undertaken has shown the importance of achieving compatible surface hardness since it affects wear. Unfortunately, at present chain hardness and wear do not seem to be considered in any detail.

In situ in-water inspection techniques are continuing to improve, but further developments are needed to provide dimensional data on links away from the inter-grip area and to improve the marine growth cleaning off speed. At present no in-water techniques exist to check for possible fatigue cracks and the development of such technology should be encouraged. Inspection access needs to be improved and design briefs should assign a higher priority to designing systems which are easier to inspect.

On one long term deployed North Sea unit chain wear and corrosion in the thrash zone has been found to be significantly higher than what is specified by most mooring design codes. This wear seems to be more pronounced on less heavily loaded leeward lines compared to the more loaded windward lines. Hence, it appears that more interlink rotation is occurring on the leeward lines. More data is needed to find out if this is a general finding which could have long term implications for other FPSs in the North Sea and elsewhere.

At present there is little data available which indicates how the break strength of long term deployed mooring components will be reduced by wear, corrosion including pitting and the possible development of small fatigue cracks. Thus to assess long term integrity with any confidence it is recommended that break tests on a statistically representative sample number of worn components should be undertaken. Recovered lines from the thrash zone and from the fairleads/chain stopper area would be ideal for testing. Such material is likely to be available whenever a FPS comes off station or has repairs done to its moorings. As well as break tests, MPI, photographs and comprehensive dimension measurements should be undertaken. It is important that this data should be fed back to the industry. Certain North Sea Operators have shown a willingness to make this data available.

Offset monitoring has limitations in quickly detecting line failure unless a FPS is in deep water. However, it is cheap and easily installed. Hence it should be installed as standard on all units. In addition, all units should know the maximum sea state in which they can continue to produce in case one line fails. On board emergency procedures should identify what action should be taken in case of riser rupture while the risers are still pressurized, although the likelihood of this happening is low.

A possible contributory mechanism for the relatively high failure line failure rate among drilling semi-submersibles has been identified. This is believed to be due to rigs thinking they have set up balanced pre-tensions when in fact this has not been achieved. Hence, it is recommended that Pay-In/Pay-Out tests should be undertaken to check whether the line tension readings can be relied upon,

Finally a general lack of suitable spare lines, connectors and repair procedures has been noted. Given the substantial procurement lead-time associated with these items it is recommended that Operators should review their assets to see how they could deal in the short term with one or more failed lines. The reported statistics show that line failures have been higher than might normally be expected for custom designed systems which are not regularly recovered and redeployed. Thus the business interruption potential due to mooring problems should not be underestimated.

Acknowledgements

The crucial support to this project provided by the following supporting organizations is gratefully acknowledged: B.P., Chevron Texaco, ENI, Norsk Hydro, PetroCanada, Statoil, Bluewater, SBM, Maersk Contractors/North Sea Production Company, Wood Group/Amerada Hess, Bureau Veritas, ABS, Lloyd’s Register, U.K. Health and Safety Executive (HSE), Craig Group/IMS, Vicinay Cadenas, Ansell Jones/Oceanside, MARIN, OIL/Zhengmao, Welaptega Marine, Balmoral Marine, BMT/SMS, National Oilwell-Hydralift/BLM, Hamanaka Chains and in particular to Williams Marine Enterprises.

The project Steering Committee itself has been exceptionally strong and it is hoped that it will be possible for the committee to continue to meet during future FPSO Forum/JIP Weeks. This will provide a continuing reporting/recording mechanism as more data becomes available. New participants to this committee will be welcome.

References

1. “FPS Mooring Integrity JIP Report”, A4163, 2005, Noble Denton Europe Limited, Aberdeen.

2. “Analysis of Accident Statistics for Floating Monohull and Fixed Installations” HSE Research Report 047, 2003.

3. “Recommended Practice for Design and Analysis of Station-keeping Systems for Floating Structures”, API RP 2SK, 1997.

4. “Position Mooring,” DNV Offshore Standard OS E301, June 2001 5. “Design and Integrity Management of Mobile Installation

Moorings,” HSE Research report 219, 2004 6. “Station-keeping systems for floating offshore structures and

mobile offshore units,” ISO Draft International Standard, ISO/DIS 19901-7, Part 7, 2004

7. “Cost Effective Mooring Integrity Inspection Methods,” Hall, A.D., OTC 2005, May 2-5, Houston, paper 17498

8. “Review of Mooring Incidents in the Storms of October 1991 and January 1992,” HSE Offshore Technology Report – OTO 92 013.

9. “Failure of Chains by Bending on Deepwater Mooring Systems,” Philippe, J., OTC 2005, paper17238.

10.“Marine Bio-deterioration : an interdisciplinary Study,” Costlow, J.D., and Tipper R.C. (Eds.), pp. 384, Naval Institute Press, Annapolis, Maryland, 1988.

A4163-01 281

26 APPENDIX D – HSE SAFETY NOTICE 3.2005

FLOATING PRODUCTION AND OFFLOADING

(FPSO) MOORING INSPECTION

Floating Production Storage and Offloading (FPSO) -

Mooring Inspection Safety notice: 3/2005

Issue date: Apr 2005

Introduction

1. This notice is for operators of monohull weather vaning FPSOs and FSUs. It

explains why they need to ensure that the top sections of their mooring chains are

not subject to excessive wear that can affect the integrity of the mooring system.

Background

2. It has come to the attention of HSE that premature and unexpected mooring chain

wear has been experienced on one UKCS FPSO inside the trumpet connected to

the turret's chain table (spider). Essentially, the mooring chain is directed through

a carefully designed trumpet that has the ability to rotate about a horizontal axis

and thus accommodate the vertical motions of the FPSO without transferring

significant bending or twist into the mooring chain.

3. Damage to chain links at the trumpet bell mouth, within the trumpet body itself,

and around the chain stopper suggests that unexpected wear is occurring. The

exact cause of the wear has as yet not been ascertained. Causes might include

inaccurate offshore installation, defective design of the trumpet and/or unforeseen

load conditions at the trumpet.

4. The wear experienced is generally manifested as a loss of cross-sectional area. In

some chain links the loss of material has been such that retained strength would be

insufficient to achieve design factors of safety. Furthermore, the deterioration in

the chain links has occurred after just 4 years into a 20-year design life.

5. The principal concern to HSE is that similar wear mechanisms may be taking

place on other floating installations that have mooring chains passing through a

trumpet. Defects that affect more than one mooring chain can increase the risk of

multiple mooring line or system failure.

Action required

6. Operators of FPSO and FSU installation need to be aware of such occurrences,

and to ensure that they have suitable inspection routines in place.

7. Operators should inspect the mooring chains around and inside the mooring

trumpet during 2005, and take any necessary remedial action to ensure the

continuing integrity of the mooring system.

8. Periodic inspection of the chain around and inside the trumpet should be carried

out based upon the findings of the initial inspection.

Further information

Any queries relating to this notice should be addressed to:

Health and Safety Executive Hazardous Installations Directorate Offshore Division Lord Cullen House Fraser Place Aberdeen AB25 3UB Tel: 01224 252500 Fax: 01224 252615

This guidance is issued by the Health and Safety Executive. Following the guidance is not compulsory and you are free to take other action. But if you do follow the guidance you will normally be doing enough to comply with the law. Health and safety inspectors seek to secure compliance with the law and may refer to this guidance as illustrating good practice.

Updated 27.09.05

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