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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 1BQor by e-mail to [email protected]



HSEHealth & Safety

Executive

Floating production system

JIP FPS mooring integrity

Noble Denton Europe LimitedNo 1 The Exchange

62 Market Street Aberdeen

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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CONTENTSSECTION PAGE NO.

1 EXECUTIVE SUMMARY 11

2 INTRODUCTION AND SCOPE 17

3 MOORINGS OVERVIEW 22 3.1 Mooring Basics 22 3.2 Mooring Line Constituents 39 3.3 Determination of Minimum Break Load (MBL) & Maximum Stresses 58

4 CONTEXT SETTING - HISTORICAL INCIDENTS AND THEIRSIGNIFICANCE 65

4.1 Long-Term Degradation Mechanisms 65

4.2 Multiple Line Failure Incidents 74 4.3 “Petrojarl 1” Multiple Lines Failure (1994) 76

5 CONSEQUENCES OF MOORING LINE FAILURE 77 5.1 Single Line Failure 77 5.2 Multiple Line Failure 79 5.3 Danger of Hydrocarbon Release 81 5.4 Business Interruption Consequences - Two Case Studies 82

6 HANDLING, TRANSPORTATION/TRANSFER AND INSTALLATION 85 6.1 Transportation/Transfer 85 6.2 Installation of Mooring Lines and Connectors 86 6.3 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 99 7.2 Corrosion and Wear Allowance – Discussion of Code Requirements 101 7.3 North Sea FPSO – Apparent Corrosion and Wear Data 108 7.4 Sulphate Reducing Bacteria (SRB) Induced Pitting Corrosion 112 7.5 Stress Corrosion Fatigue 113 7.6 Wear Analysis (Shoup and Mueller Work) 118

8 UNBALANCED LINE PRE-TENSIONS (CASE STUDIES) 122 8.1 North Sea Semi-Submersible FPS 122 8.2 Line Payout/Pull-In Test 123 8.3 North Sea FPSO 124

9 MOORING BEHAVIOUR AT THE VESSEL INTERFACE (CASE STUDIES) 126 9.1 Permanently Stoppered Off Versus Adjustable Lines 126 9.2 Wear at Trumpet Welds – Internal and External Turrets 130 9.3 Use of Bending Shoes 143

10 FURTHER MOORING CASE STUDIES 145 10.1 Wire Rope Systems 145 10.2 Unintended Line Disconnection 146 10.3 Excursion Limiting Weighted Chain Problems 151 10.4 Line Run Outs and Quick Releases 155 10.5 Windlass Failures 158

11 SPARS AND OFFLOADING BUOYS (CASE STUDIES) 160 11.1 Brent Spar Buoy 160 11.2 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 169 13.2 Summary Statistics for Unit Type and Geographical Area 171 13.3 HSE UK Sector and Norwegian Statistics 174

14 CONNECTORS AND TERMINATIONS 177 14.1 Background 177 14.2 What Type of Connectors Can be Considered for Long Term Mooring (LTM ) 177 14.3 Terminations General 182 14.4 Connector/Termination Design Flow Chart 186 14.5 Detailed Design Guidance 189 14.6 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 197

15.2 Tension Bending at Chainhawse 205 15.3 Tension Bending In Wire Rope 215 15.4 General Implications of Tension Bending Fatigue for the FPS Industry 219 15.5 Recommendations 222

16 FRACTURE MECHANICS AND CRITICAL CRACK SIZE 223 16.1 Required Data 223 16.2 Fracture Mechanics and Chains – State of the Art Summary 224 16.3 Fracture Mechanics Critical Crack Size Implications 225

17 LINE STATUS MONITORING AND FAILURE DETECTION 226 17.1 Instrumentation Status - Survey Results 226 17.2 Existing Failure Detection Systems 227 17.3 Future Failure Detection Systems 232

18 INSPECTION, REPAIR & MAINTENANCE (IRM) 238 18.1 In Air-Inspection 238 18.2 Where to Inspect on a Mooring Line 239 18.3 In-Water Inspection 242 18.4 Marine Growth Removal 246 18.5 Manufacturing Tolerances and the Inspection Implications 247 18.6 Wildcat/Gypsywheel Inspection 247 18.7 Inspection Frequency – Code Requirements 255 18.8 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 DESIGNSPECIFICATION 264

20.1 Installation Parameters 265

21 KEY CONCLUSIONS & FUTURE WORK RECOMMENDATIONS 267 21.1 Overview 267 21.2 Key Conclusions 268 21.3 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 PRODUCTIONAND 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] ................................... 12Table 1-2 - Indicative Single Mooring Line Failure Costs ........................................................... 13Table 3-1 – Summary of Chain Design Parameters (modified from Vicinay Chain Catalogue).. 41Table 3-2 – Comparison of Manufacturing Parameters ................................................................ 41Table 3-3 – Chain Geometry Implications for Inspection and Maintenance ................................ 42Table 3-4 - Summary of Ship or Marine Grade Chains [Ref. 13]................................................. 45Table 3-5 – Example of Indicative Surface Hardness Values for Various Chain Grades (courtesy

of Vicinay)............................................................................................................................. 46Table 3-6 – Illustration of Indicative Wire Rope Material Properties [Ref. 2] ............................. 49Table 3-7 - Comparison of the Advantages of Spiral and Six Strand Wire (courtesy of Bridon) 50Table 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) ........... 50Table 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 ............................................ 83Table 5-2 - Line failure Cost Estimate, 250,000bpd West African FPSO .................................... 84Table 7-1 - Example of Specified Corrosion and Wear Allowances from One Classification

Society ................................................................................................................................. 102Table 12-1 - Summary of the Pros and Cons of Sliding and Roller Bearings [Ref. 48] ............. 167

............................................................................................................................................. 169Table 13-1 - Example of the First Page of the Questionnaire – see appendix B for a Full Listing

Table 13-2 - UK Sector of the North Sea Data [Ref. 49].......................................................... 174Table 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] .............................................................................................................................. 174Table 15-1 – Comparison between Chain Tension-Bending Fatigue Parameters Note that values

in italics are derived from BOMEL measured stress factor. ............................................... 203Table 15-2 : Wire Rope Fatigue Reduction Due to Tension Bending [Ref. 31] ......................... 216Table 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 .................................. 14Figure 2-1 - JIP Organisation ........................................................................................................ 19

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

Offshore) ............................................................................................................................... 26Figure 3-8 – Illustration of Catenary System................................................................................ 28Figure 3-9 - Typical Spread Moored Catenary System (Courtesy of Vryhof) ............................. 28

Figure 3-10 – Illustration of Taut-Leg system .............................................................................. 29Figure 3-11 - Typical Spread Moored Taut-Leg System (Vryhof) ............................................... 29

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

Figure 6-2 - Illustration of the Weight and Handling Issues Associated with Mooring

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

Figure 6-9 – Pre-Stretching Polyester lines During Installation to Minimise the Requirement for

Figure 6-10 - Illustration of the Potential Difficulty in offshore alignment of pins on large

Figure 6-11 - Sledge used to Protect “H” Connector during Deployment over the Stern Roller

Figure 7-3 Illustration of the Extent of General Corrosion on a Recovered Floating Production

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

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

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

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

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

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

Figure 5-3 - Potential Multiple Line Failure Scenario .................................................................. 80Figure 5-4 - Example of how Mooring Integrity Philosophy can affect Production .................... 81Figure 6-1 - Spooling Fibre rope onto a Powered Reel from Standard Containers ...................... 85

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

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

Future Line Length Adjustments [Ref. 27] ........................................................................... 96

Diameter Rope [Ref. 26] ....................................................................................................... 97

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

(Courtesy of CNR) ................................................................................................................ 99Figure 7-2 – Plan View of Mooring Incidents at Balmoral........................................................ 100

Unit Mooring Line after 16 years service ........................................................................... 103Figure 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

............................................................................................................................................. 105

............................................................................................................................................. 106Figure 7-8 Finite Element Stress Contour Plot (compare red areas with Figure 7-6) [Ref. 8] .. 106Figure 7-9 - Example of Thrash Zone Wear .............................................................................. 107Figure 7-10 - Illustration of the Extent of Pitting Corrosion...................................................... 108Figure 7-11 - Example of Wear and Pitting Corrosion on the Shackle Pin ............................... 109

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

[Ref. 34] .............................................................................................................................. 119Figure 8-1 – Illustration of Line Tension Variations during a Payout/Pull-In Test .................... 123

Texaco)................................................................................................................................ 127

(courtesy of Bluewater) ....................................................................................................... 127 Figure 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 Weldswhich 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 Figure 9-6- Test Tank Mock-Up of Micro-ROV inspection of Chain Emerging from Turret

Figure 9-7 - Micro-ROV Photograph of Chain Wear Notches where Chain Emerges at the

Figure 9-9 - Artificially Introduced Notch on to Spare Chain Links, note also Red Circular

Figure 9-10 - Example of Stretched Chain during Break Testing, the Blue Mark Shows the

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

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

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

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

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

Figure 9-18 – Typical CALM Buoy Chain Stopper (courtesy of “The Professional Diver’s

Figure 10-1 – Examples of the Subjectivity Associated with Assessing IWRC Rope Conditions

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

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

Figure 10-14 - Weighted Chain Option Utilising Parallel Chain Sections (courtesy of

Workclass ROV (courtesy of I.Williams) ........................................................................... 131

“Trumpet” (courtesy of I. Williams) ................................................................................... 132

Trumpet Bell Mouth (courtesy of I. Williams) ................................................................... 132Figure 9-8 - Indication of the Extent of the Wear ...................................................................... 133

Infrared Target (courtesy of I. Williams) ............................................................................ 134

Location of a Typical Notch (courtesy of I. Williams) ....................................................... 134

Williams) ............................................................................................................................. 135

............................................................................................................................................. 136

recovered back to Shore (courtesy of I. Williams).............................................................. 136

(2 black concentric circles) ................................................................................................. 137

............................................................................................................................................. 138

(used on some Spread Moored FPSOs) (courtesy of Maritime Pusnes) ............................. 138

Maritime Pusnes)................................................................................................................. 139

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

[Ref. 43] .............................................................................................................................. 145Figure 10-2 - Illustration of the Mooring Layout and Connections ............................................ 146

Offshore) ............................................................................................................................. 147

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

N.Groves) ............................................................................................................................ 1537



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

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

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

Corner (courtesy of BP) ...................................................................................................... 158 Figure 11-1 - General Arrangement of the Brent Spar Mooring System (courtesy of Shell) ..... 160Figure 11-2 - Brent Spar Fairlead Chain Stopper in the Hull (courtesy of Shell)....................... 161Figure 11-3 - Close Up of the Stopper (courtesy of Shell) ......................................................... 161Figure 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 ofShell) ................................................................................................................................... 162

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

(courtesy of Shell) ............................................................................................................... 164Figure 13-1 - Comparison of Mooring Line Inspection Periods for Different FPS Categories. 173Figure 13-2 – Historical Failure Rates for Different Types of Units ......................................... 176Figure 14-1 - Special Joining Shackle (courtesy of Vicinay Catalogue) .................................... 179Figure 14-2 - “H” Shackle Pin Configuration (courtesy of I. Williams) .................................... 180Figure 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 ................... 181Figure 14-5 – Example of the Make Up of a Typical Closed Spelter Socket (courtesy of Bridon)

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

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

the “H” Shackle ................................................................................................................... 191Figure 14-12 - Example of Material with a Non Clearly Defined Yield Point .......................... 194Figure 15-1 Broken Link from Fairlead ... ..................................................................................197 Figure 15-2 Mechanical Damage on Fairlead Link ................................................................ ... 197 Figure 15-3 - Support of a Link in a Wheel Fairlead ................................................................. 198Figure 15-4 - Photograph of Test Link Showing Bearing Plates [Ref. 10]................................. 199 Figure 15-5 - General View of Tension Bending Test Rig (protective screens removed for

clarity) [Ref. 10] ................................................................................................................. 199 Figure 15-6 - Broken Hardened Plates at the end of the First Test [Ref. 10] ............................. 200Figure 15-7 - Twisted Link Due to Mis-aligned Butt Weld [Ref. 10] ........................................ 201Figure 15-8 - Simple Out of Flatness Twist Measurement Jig [Ref. 10] .................................... 201Figure 15-9 - Illustration of Failed Link Due to Tension Bending [Ref. 10].............................. 204Figure 15-10 - Girassol Offloading Buoy [Ref. 55]................................................................... 205Figure 15-11 - Girassol Offloading Buoy – Failure in Chain Link 5 [Ref. 55] ......................... 206Figure 15-12 - Girassol Offloading Buoy – Failure in Polyester Rope [Ref. 55] ...................... 206Figure 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 15-20 - Tension Bending at Wheel Fairlead (Bearing Load Eccentricity) and Tension

Figure 17-3 - Sonar Display Screen Showing 12 Mooring Lines and 2 Risers Close to the Centre

Figure 17-7 - Indication of the Data Available from Instrumented Mooring Lines (courtesy of

Figure 17-8 - Illustration of a New Sonar System due to be Installed in the North Seas (courtesy

Figure 18-1 - Red Arrows and Black Line Indicate Key Areas subject to Degradation on a

Figure 18-3 - Typical Turret Cross Section Illustrating that the key Mooring Components are

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

Figure 18-5 - Illustration of ROV Deployed ‘Optical Calliper’ Measurement System (courtesy

Figure 18-10 - Red Zones Highlight the Importance of Checking all Relevant Structural

Figure 18-11 - Example of a Parted Lubrication Line Feeding a Submerged Wildcat or Gypsy

Figure 18-16 - Partially Buried Shackle Illustrates the Difficulties in checking locking pins

Figure 18-17 - Example of the Wheel Tappers Approach Used for Detecting Cracks on Railway

Figure 18-18 - Example of Anchor Handling and Heading Control Tugs during a Mooring Line

Figure 18-19 - Use of Divers from a RIB to open up the Chain Stopper during a FPSO Mooring

Figure 15-15 - Schematic of SBM Test Rig [Ref. 55] ............................................................... 209

Figure 15-16 - Photograph of SBM’s Test Rig [Ref. 55]............................................................ 210Figure 15-17 - Typical FPSO Chain Stopper Arrangement ........................................................ 211Figure 15-18 – Illustration of Wire Rope Failure Modes (courtesy of Bridon) .......................... 217Figure 15-19 - The 1.0MN Wire Rope Bending-Tension Fatigue Test Machine ....................... 218

Bending from Interlink Friction (Torque at Contact).......................................................... 219Figure 15-21 - Comparison between Various Mooring Chain S-N Curves ............................... 221Figure 17-1 - Sonar Fish for Deployment through Turret (courtesy Chevron Texaco) ............. 227Figure 17-2 – Sonar Fish Deployment Method (courtesy Chevron Texaco) .............................. 227

(courtesty Chevron Texaco) ................................................................................................ 228Figure 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) ....................... 229Figure 17-6 - Instrumented Load Pin – Shackle Link (courtesy of BMT/SMS)......................... 230

BMT/SMS).......................................................................................................................... 231

of I. Williams) ..................................................................................................................... 233Figure 17-9 - Close Up of the Proposed Sonar Head (courtesy of Ian Williams)...................... 233Figure 17-10 - Response Learning Without Line Tension Input ................................................ 234Figure 17-11 - Illustration of Riser Monitoring Instrumentation (courtesy of 2H) .................... 236

Mooring System (leeward likely to have worst wear) ........................................................ 239Figure 18-2 - Example of a Weight Discontinuity which may Result In Enhanced Wear ......... 240

Submerged........................................................................................................................... 241

(compare to Figure 18-3)..................................................................................................... 242

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

Connections (Courtesy of CNR) ......................................................................................... 249

Wheel (Courtesy of CNR)................................................................................................... 250Figure 18-12 - Example of a Non Flat Link ................................................................................ 251Figure 18-13 - Buchan FPS Wire Rope NDT Inspection Head ................................................. 252Figure 18-14 - Proposed Wire Rope Inspection Toll Delpoyed from a ROV............................ 253Figure 18-15 - Example of a Difficult Area to Inspect .............................................................. 256

(courtesy of ENI)................................................................................................................. 256

Carriages and Locomotives ................................................................................................. 258

Repair Operation (courtesy of I. Williams)........................................................................ 259

Line Repair (coutesy of I. Williams)................................................................................... 2609



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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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1.3 Indicative Mooring Statistics

At the beginning of the project it was hoped that it would be possible to gain data onthe 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 beenobtained is for North Sea Units, partly due to local contacts and also the rigorousreporting regime in this area. In the absence of more comprehensive information, itthus seems prudent to consider official statistics for this region to be the best availableindicator of the likelihood of mooring failure. Exactly how these statistics can berelated to milder environments is difficult to quantify based on the presently availabledata set.

Table 1-1 summarises failure statistics for North Sea operations for different floatingunits 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 OperatingYears 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 mightimagine that they would be heavily instrumented with automatic alarms which wouldgo off in case of line failure. The following indicative statistics, based on data from themajority of North Sea based FPSOs, give an indication that instrumentation is not as

prevalent as might be expected for such a heavily regulated region:

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

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

x 78% of units do not have line failure alarms,

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

x 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 costand the implications for the whole FPS industry could be extremely high, depending oncircumstances. Even a single mooring line failure would be costly as is illustrated inTable 1-2 for two different case studies, further details can be found in Section 5.4.

Description Approx. Cost ofSingle 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 stopperneeds 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 alsorequires addressing based on further in field experience. This may have particularimplications for spread moored FPSOs. Access for inspection of these areas also needsto be improved and this should be specified in the mooring design criteria – see Section20.

Wear/Corrosion Allowance for Long-Term Moored Units

On two North Sea FPSs chain wear and corrosion has been found to be significantlyhigher than what is specified by most mooring design codes. More in field inspectiondata is needed to find out if this is a general finding, which could have long-termimplications 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 ifthey are due to operate in adverse environmental conditions. Parallel chains seem tohave 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, althoughwater depth, riser offset limits and environmental conditions may mean that this is notalways possible.

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Local Design of Connectors

Connectors are vital components on any mooring system and they need to be verycarefully 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 asummary of key items which should be considered during detailed connector design.There is an emerging need for the development of a fatigue resistant connector suitablefor use with mooring chains during repair/overhaul operations.

Friction Induced Bending

Friction induced bending fatigue appears to be a significant issue which has beensomewhat neglected and warrants further investigation. This was less of an issue forcatenary 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. TheFPS has been displaced by environmental forces, thus illustrating both windward andleeward mooring lines.

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

From a number of units it has become clear that the less loaded leeward lines can besubject to greater degradation than the windward lines. This seems to be due to greaterrelative 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 astorm while still producing and thus being at an increased danger of loosing anothermooring line.

Detecting a line failure in the mud is difficult since the catenary shape, depending onsea-bed conditions, may not change that much. Section 17 summarises the keydetection techniques available at present. It is clear that in-field trials are required toidentify what systems prove to be reliable over the long-term. Hence, this is an ongoing 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 linerecovery to the surface and also during re-installation. There is also a significant costinvolved 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 possiblecracks. Despite this it has become clear that many possible problems can be identifiedearly on, using tweaks to existing technology. This has been successful as long assuitably 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 incidentshave occurred in the past including loss of station. The survey has also shown thateven for more up to date designs, deterioration of certain areas of the moorings systemmay be more rapid than expected. As well as the detail issues there is a more generalissue that requires addressing, namely the manner in which mooring integrity ismanaged and audited on an on-going basis.

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

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Semi-submersible units have accumulated hundreds of years of mooring experience forvaried world wide locations. A key point to learn from such units is that chains, wireropes, gypsy wheels, stoppers and connectors have finite lives and do wear out.Although drilling rigs deploy and recover lines fairly regularly, which can causedamage, 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 onthe expectation that the mooring lines will last for the life of the field and that safetywill not be compromised towards the tail end of the field life, when production rateshave dropped. If production rates have dropped there is less money available formooring line repairs. Hence, assessments should be undertaken during the field life toassess 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 structuralmembers subject to constant dynamic motion. Expecting such systems to last for 20+years without overhaul may prove to be optimistic. The commercial risks associatedwith a line failure during the field life justify the selection of top quality equipmentfrom the outset. This equipment then needs to be regularly inspected and repaired asrequired to ensure that it is still fit for purpose.

Availability of mooring line spares including connectors is extremely variable. Giventhe several month lead-time associated with procuring new components, it isrecommended that each operator should identify short term remedial measures to repaira 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 carefulmanagement through out their design lives. Thus a life cycle approach to mooringdesign and operation is recommended. In this way designers can feedback theirinspection requirements to Operators and then learn from whatever is found duringinspection. Manufacturers should also be included in this feedback loop, since theymay be best placed to implement improvements to their products. Hence over timemooring design and manufacturing should improve. At present designers andmanufacturers are not always involved with the in field behaviour mooring systems.Therefore, they may not be aware of operational or inspection type issues. In generalthere 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 integritya number of topics still require further investigation. A bullet point list is included inSection 21.3.

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2 INTRODUCTION AND SCOPE2.1 The Need for a JIP

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

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

x Several cases occurred in which there was systematic damage to morethan one line;

x Particular problems have been experienced at connectors and interfaces;

x In no cases was the damage recognised immediately;

x Long-term failure rates remain uncertain.

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

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

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

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

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

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

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DESIGN AND CONSTRUCTION ISSUES

CTR 2 :Transportation, Handling & InstallationChallenges

CTR 3 :Design of Connectors & Interfaces

INTERNATIONAL SURVEY OFMOORING PROBLEMS

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

DISSEMINATIONOF RESULTS

(CTR 10)

Lessons Learned

Detailed Report

Integrity Check List

2.4 Project Organization

The project organisation is illustrated in Figure 2-1.

Martin Brown

COMMITTEE

Project Manager

STEERING

Nigel Robinson NDE Project Director

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

ND Group Resources & Subcontractors

Figure 2-1 - JIP Organisation

The scope of work was broken down into Cost, Time, and Resource Modules [CTRs],

which were organized as follows:

:

p

::

Water Survey:

DISSEMINATIONOF RESULTS

(CTR 10)

Bulletins/Steering

OTC paper

Detailed Report

DESIGN AND CONSTRUCTION ISSUES

CTR 2 : Transportation, Handling & InstallationChallenges

CTR 3 Design of Connectors & Interfaces

INTERNATIONAL SURVEY OFMOORING PROBLEMS

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

INTEGRITY MANAGEMENT

CTR 5 Status Monitoring and Failure DetectionCTR 6 Inspection, Repair & Maintenance, inc In

CTR 7 Sparing Options

Lessons Learned

Committee briefings

Figure 2-2 - CTR Breakdown

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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 SteeringCommittee 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 Stauttener5. 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 Larsen21. Vicinay Cadenas, Dave Nicol and Eduardo Lopez

22. Welaptega Marine, Tony Hall

Many people from various organisations helped out through out the JIP by providinginformation. It is impossible to list them all, but their combined support has beencrucial 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 highlyrelevant data readily available to the JIP. Thanks also to Diane for all her assistancewith 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 andParis were part of the FPSO Forum/JIP Week. The Aberdeen meeting was a standalonemeeting.

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

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

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3 MOORINGS OVERVIEW3.1 Mooring Basics3.1.1 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. Thissubject is covered in this chapter, which also includes a simple introduction to howsuch systems can be analysed.

The primary purpose of a mooring system is to maintain a floating structure on stationwithin a specified tolerance, typically based on an offset limit determined from theconfiguration 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 thefollowing diagrams the main components of mooring system restoring force areexplained.

The connection between the mooring system and the body of the vessel is where therestoring force of the mooring system acts, see Figure 3-1. At this connection pointthere are two force components present; horizontal and vertical. The horizontalcomponent of the mooring line’s tension acts as a restoring force. The verticalcomponent 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, thevertical 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 departsthe point of connection to the vessel. A low angle to the vertical will generate a lowrestoring 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 bereduced. This relationship can be seen in Figure 3-2. The vessel needs to be able tosupport 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 dimensionalscenario. The mooring of a vessel, however, is a 3 dimensional problem and to this endit 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 splitinto two components; the restoring force that opposes the environmental loading, andthe lateral force, which may balanced by another mooring line.

Figure 3-3 – Line Heading Illustration

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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 loadexcursion characteristics of a 1,200m long, 76mm nominal diameter chain in 100mwater depth with a working or pretension tension of 100te. The plot emphasizes theneed to model the axial elasticity, even for chains, in order to get realistic results. Axialelasticity depends on geometry and material. Since there are new materials andgeometries available in the market, it is important that designers should confirm withmanufacturers 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 PointMooring systems, which are taken to include turret systems. The key attributes of eachare discussed in this section.

Spread Mooring

This conventional mooring approach is widely adopted for semi-submersibledrilling/flotel/production units. For floating production applications, spread mooringsare used primarily with semi-submersibles and non-weathervaning FPSOs (i.e. noturret) – see Figure 3-7. Since the wave loading on a semi-submersible is relativelyinsensitive to direction, a spread mooring system can be designed to hold a semi onlocation regardless of the direction of the environment, although there is probably anoptimum heading. However, a spread system can also be applied to ship-shapedvessels, which are more sensitive to environmental directions, as long as theenvironmental conditions are relatively benign and the weather direction is fairlyuniform without strong cross currents. In a location such as the North Sea, the forceswhich can be generated on the beam of a spread moored FPSO, plus the motions insuch 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 mooringlines.

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 mechanicallyfar 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 primarilyfor ship shaped units – see Figure 3-1. They allow the vessel to weathervane, which isnecessary to minimise environmental loads on the vessel by heading into the prevailingweather. There is a wide variety in the design of SPMs, but they all perform essentiallythe 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 Pointsystem; Taut-Leg and Catenary. Both methods allow the system to withstand theapplied forces, but through different mechanisms.

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

A ‘taut-leg’ system makes use of the material properties of the mooring line, namely itselasticity, as shown in Figure 3-10. A typical taut-leg arrangement is shown in Figure3-11. 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-orderresponse. As a mooring line moves through the water it will be subject to dynamic linedrag and inertia loading and sometimes a whipping effect. It is possible to take thisinto account by undertaking a dynamic mooring analysis, but this does increasecomputing 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 themooring system is not considered to affect the wave frequency response. The overall

mooring system stiffness and associated natural frequency will influence its secondorder or low frequency slow drift response.

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

The coupled wave frequency motion of a floater can be calculated in the time domainusing the wave force, wave frequency added mass and damping, and mooring force ateach time step. Usually a convolution method needs to be adopted in the radiationforce calculation. Although the coupled wave frequency motion calculation in the timedomain is slower than the Response Amplitude Operator (RAO) based wave frequencymotion calculation, it is still acceptable. Typically a 3 hour simulation will take a fewminutes. However if there is very high mooring stiffness or if a mooring dynamicanalysis 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:

x Static component from Wind, Mean Wave Drift and Current,x Wave frequency component, caused by 1st order wave frequency motions and

drag/inertia effects on the line,x Low frequency component, due to 2 nd order low frequency waves and wind

dynamics.

The essence of mooring design is to optimise the behaviour of the mooring system suchthat the excursions of the surface vessel do not exceed the allowable flexible riseroffsets, while at the same time ensuring that the line tensions are within their allowablevalues. 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 asystem for a particular location.

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It is worth noting that spring buoys (mid water buoys) and clump weights can also beused to obtain an optimised mooring system stiffness by extending the resistive forcesover greater distances, hence allowing clearance over subsea features. However, theiruse should be treated with caution, particularly in areas subject to harsh environmentalconditions, where they have been known to come adrift – see Section 9.3. Buoys andclump weights are also likely to introduce bending effects which may have anundesirable 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 applicationof specialist computer programmes, which in many cases have been under continuousdevelopment for a number of years. Despite this, there are still uncertainties inestimating mooring loads using analysis software and model tests. Hence, it would bedesirable to compare the behaviour of a full scale FPS in known weather conditionsversus predictions. Surprisingly little work has been done on this topic, although this is

partly due to the difficulties associated with obtaining reliable weather andinstrumentation 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 thrusterassistance.

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

1. Leeward line slackening,

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

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

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

“in practise rig operators are reluctant to adjust windward line tensions insevere weather conditions and usually restrict adjustments, if any, toslackening leeward lines. This is partly to do with limitations in winch stallcapacity and the risk of a winch or brake failure, but most importantly themajority of rigs are not provided with suitable tension monitoring devices andcomputerised winch control systems which would make extensive line tensionoptimisation a realistic possibility. The general situation is that analystsfrequently utilise line optimisation to reduce tensions to meet acceptancecriteria but these line tension optimisation procedures are almost neverimplemented in practice on a rig.”

Based on this type of feedback the latest mooring design codes (e.g. ISO [Ref. 4] + OSE301 [Ref. 5]) do not permit either windward or leeward active wincing to minimisemooring line tensions apart from going from one operational state to another.

Thruster AssistanceA number of semi-submersibles and a relatively small number of FPSOs are equippedwith thruster assistance. The thruster assistance can be categorised as either ThrusterAssistance (TA) or Automatic Thruster Assistance (ATA). TA is based on manual

joystick thruster control. ATA makes use of automatic remote control algorithmsystem 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 peakline 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 mooringsystem. However, thrusters also seem to damp down the magnitude of the slow driftsecond order offsets. They can also be helpful with respect to heading control. Thiscan be particularly useful on a production vessel, if a small change in heading can resultin 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 thevessel in the direction of the advancing sea. As the wave passes it is necessary to easedown 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 passesthrough.

3.1.9 Metocean Parameters and their Impact on Mooring Integrity

For relatively benign environments, such as off West Africa, there is a much smallerdifference 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 margincompared 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 affectmooring analysis results. The geographic area and fetch distance will influence thetype of waves likely to be encountered in practice. Conventionally, short crested seasare considered to result in reduced wave frequency response and hence reducedmooring line tensions - see section 3.3.2 of [Ref. 6]. However, recent model test resultsat DHI in Denmark has shown that for certain vessel sizes the mooring loads in shortcrested waves can be higher than in long crested waves [Ref. 7]. Thus the key point isto ensure that the response of the system is thoroughly evaluated for the worst expectedconditions (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 oreven Holes in the Sea”, to describe some of the conditions they have experienced atsea. Trading vessels are typically weather routed to avoid the worst of predictedweather conditions. However, permanently moored FPSs have to ride out whateverweather is thrown at them.

From a statistical sense the longer a FPS is on station the more likely it is to experience100 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, thelikelihood of single or even multiple line failure is increased.

Very occasionally an unusually steep wave slam load could occur at the same time thata floating structure is around its maximum slow drift offset. The resulting shock orspike load on the mooring might be quite considerable. How much this shock loadingis transferred to the mooring lines will depend to a significant extent on the degree ofstructural damping in the hull structure, the vessel inertia, how long the load acts andwhere the moorings are relative to where the wave impacts. For a semi, where youmight get wave slam/slap right into one of the corners (see Figure 3-16), the amount ofstructural damping might well be less than compared say to a FPSO with an internalturret (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 canoccur – see Figure 3-17. In addition, a "Three Sisters" wave group can occur in whichthe 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 theLeft and Spilling Breaking on the Right)

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

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

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Present day standard mooring analysis tools do not evaluate this potential shock loadeffect 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 tothe virtually instantaneous multiple line failures experienced by “Petrograd 1” in theearly 1990s (see Section 4.3). This might also be a factor in the relatively frequentmooring 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 reallife recorded response of FPSs in severe/steep sea weather conditions. However, it alsoshould 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 (Courtesyof APL website)

The right hand side photograph of Figure 3-19 is perhaps an example of the type ofwave conditions which could impart a shock loading to the moorings, depending on theFPSO 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 linefailures 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 mooringline. The pros and cons of the various types of line components are explained. Thishelps to aid understanding when considering how actual systems have performed insitu. 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 ofthis design led to usage of studded links, see for example Figure 3-20. Ease ofhandling and avoidance of kinking were the primary reasons for the introduction ofstuds. The resulting link geometry (see Figure 3-21) took advantage of the ability ofthe stud to resist some of the bending loads in the links. The studded link standardgeometry of length of 6 x Bar Diameter (D) and breadth of 3.6 x D was approved bythe British Admiralty in the 1860s.

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

Figure 3-20 - Isambard Kingdom Brunel in front of Studded Chain for the “GreatEastern” 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 productionsystems 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 designsare increasingly used for long-term moorings because loose and missing stud problemsare eliminated. Unfortunately, however, the fatigue life of studless chain has beenshown to be half that of comparable studded chain, based on the results of fatiguetesting [Ref. 8]. In other words the fatigue endurance of studded chains is twice that ofstudless 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 and14% 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 forthe Veslefrikk B project. For this chain the first tentative specification went out in1995 with the DNV’s Certification Note 2.6. More recent developments includecustomised chain geometries also known as Variable Geometry and Weight (VGW) asdiscussed in OTC paper 8148, 1996 [Ref. 9]. VGW provides flexibility to modify linkgeometry 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 interms of design, manufacturing, inspection and maintenance.

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Requirement RecommendedChain Reason

Eliminate premature fatigue due to loosestuds

Studless No stud, therefore no notch effect

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

Eliminate galvanic reaction between thestud and the link

Studless No stud, therefore no possibility ofreaction

Increase reliability of the chain over time To be determined Although there are no loose studsissues with studless, the fatigue

performance of studless is lessgood than that of studded

Handling and connectability with Dshackles and hooks

Studless Better access for the through pin.Minimal requirements andrestrictions

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

Handling and Manoeuvrability withrespect to bending shoes and chainstoppers

Both Certain restrictions, in generalstudless chain is more likely toknot 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, thestuds start to get loose and the seat of the studs is often the initiation point for fatiguecracking [Ref. 2 and Ref. 11].

The BOMEL JIP [Ref. 10, p.54] showed that the Stress Concentration Factor (SCF) ina studless link (a link in which the stud has been removed as opposed to a link designedto 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 amuch 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 thefollowing: (Page 11) “This ovalization occurred at the point where the edge of thefootprint forms a notch effect, which in some instances appeared quite severe. It was atthis point that the fatigue cracks were initiated and then propagated through the side ofthe link. However, on page 16 Sandberg advised that “Not all loose studs haddeveloped cracks even where the end of stud play was up to 4.0mm indicating thatmany factors play a part in the initiation and propagation of these cracks including theultimate tensile stress (UTS) of the studs. The mechanical properties for the stud areimportant, particularly with regard to yield strength, for the setting of the chain underthe 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 aloose stud can affect the stress distribution in a studded link where the stud has becomeloose. The basic theory behind SPATE (Stress Pattern Analysis by Thermal Emission)is the detection of minute changes in surface temperature due to the pseudo adiabaticresponse of a material under stress. Through an infrared detector, scanning the surfaceof a given material, relative changes in temperature are fed to a computer system forcorrelation and finally presented as a pictorial colour image of the stress pattern overthe scanned area. These pictures can be interrogated further to obtain stress values atany given point. As the stresses in the three principal planes contribute to the overalltemperature change, stress values obtained are a summation of the principal stressesgenerated 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 inthe field. The Asymmetric stud is designed in such a way that gives equal foot printson either side of the link – see Figure 3-23. In studlink chain, the ‘asymmetric’ studdesign is claimed to provide ‘more equal stud indentation and contributes to a moresymmetric 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 isstill very hot by the time the process brings the link to the stud press. Hence there is avery hot side and the other side of the link, the parent material, which has alreadystarted 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 amuch lesser extent on the parent material side. Thus, if you inspect stud link chain witha stud missing you can quite often see there is almost no foot print on the parentmaterial side.

The asymmetric stud provides equal foot prints on both sides. The asymmetric stud isthen pressed to allow it to expand thus locking the stud in place. The actualconfiguration of the stud faces are different compared to the standard studs, because theedges of the asymmetric stud are more rounded to reduce the chance of notches orcrack initiation under the studs, the studs are also flatter on one side so the stud cannotsink into the hot FBW and more rounded on the other side to fit the form of the link onthe parent material side. In addition, when the studs are expanded it puts a spring effectinto 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 thediffering yield strengths of the steel that are used in their manufacture. The Grade 1chain (designated Q1, U1 or K1 depending on whether Continental, UK or Norwegianspecification) was developed using mild steel. This grade of chain is not now used inoffshore mooring systems. The most important chain grades for the offshore industryare as follows:

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

x R3, dating from the mid 1980s with 690 MPa to meet ORQ + 10%x R3S, with 770 MPa to meet ORQ + 20%

x R4, with 860 MPa

x R4S with 950 MPa or R4 + 10%

x 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 Notesfor 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 Rgrade chain. In other words Grade 3 is different from R3. Table 3-4 below summarisesthe characteristics of Marine Grade chain:

Description Ultimate TensileStrength (MPa or

N/mm2)

MarineGrade U1

Wrought iron or mild steel 310

MarineGrade U2

Special Quality Steel 490

MarineGrade 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 arenot normally reported for different chain grades, although API 2F [Ref. 65] (section5.5) and DNV Certification Note 2.6 [Ref. 18] (section 6.6.4) mention that such valuesshould 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 thevalues 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 resultin 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 notexceed 350 HV10 (HV = Vickers hardness, similar to Brinnell in this range ofnumbers) mainly due to a sensitivity to hydrogen induced crack growth. In general thehigher the hardness the more the sensitivity increases, but this depends on steelcomposition. 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. ACharpy Impact test will give an idea of the ductility of the material and its susceptibilityto brittle fracture depending on the temperature. Therefore a Charpy test does not givea full picture of surface hardness. Charpy is concerned with mechanical fracture of thematerial. For the same steel the mechanical of fracture is more related to structuralmetallurgical.

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During chain manufacture Crack Tip Opening Displacement (CTOD) values should beevaluated 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 metalshould achieve. CTOD gives a better indication of Fracture Toughness, compared toCharpy-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 steelshave a zone of high stable values over a "plateau" region. But suddently, within veryfew 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. Theimplications 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 mooringlines. Six strand independent wire rope core (IWRC) is typically used for mobiledrilling units due to its lateral flexibility and relative cheapness. Spiral strand wire isgenerally torque balanced, the implications of which are discussed in more detail inSection 6.2.2. Sheathing has been introduced to protect the wire from corrosion. Itwill, however, be interesting to see if, over time, the sea water ingress causes corrosionunderneath the sheathing. At present there are no real techniques available to monitorsuch corrosion, see also Section 18.8.

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

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

Construction Ultimate Tensile Stress (N/mm 2)

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 ofthe 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 ofBridon)

Spiral Strand – Cons Six Strand – Cons

Easy to kink during installation – see Introduces torque into a mooring lineFigure 6-7

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 factoralong with fatigue determining mooring line service life. Heavier zinc coatings are usedon 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 zinccoatings to increase the attainable design life. An anti-corrosion blocking compoundmay 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 & zincanodes

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 blacklongitudinal stripe. The yellow colour aids in service inspection as damage shows

black against the yellow background. The black stripe can highlight any turnintroduced into the wire during installation.

3.2.9 Fibre Rope

High strength and high modulus fibre materials offer certain advantages for offshoremooring systems. The use of fibre ropes has increased substantially with the move intodeep water and as test results become available. Figure 3-27 illustrates the chronologyof 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 arenot constant and vary with the duration of load application, the load magnitude, thenumber of load cycles and the frequency of load cycles [Ref. 15]. In general, syntheticmooring lines become stiffer after a long time in service. Synthetic ropes also creepover time and this needs to be taken account of during design and installation – see forexample 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 theseabed, either partly or fully. The holding capacity of the drag embedment anchor isgenerated by the resistance of the soil in front of the anchor. The traditional dragembedment anchor is very well suited for resisting large horizontal loads, but not forlarge vertical loads.

Drag embedment anchors are generally installed by applying a load somewhere close tothe maximum anticipated intact load. At this time the anchor will have penetrated to acertain depth, but will still be capable of further penetration as the ultimate holdingcapacity of the anchor has not been reached. By this stage the anchor will havetravelled a certain horizontal distance, called the drag length. Following installation theanchor is capable of resisting loads equal to the installation load without further

penetration and drag. When the installation load is exceeded, the anchor shouldcontinue to penetrate and drag until the soil is capable of providing sufficient resistanceto 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 dragembedment anchor. During installation the load arrives at an angle of approximately45° to 50° to the fluke. After triggering the anchor to the normal load position, the loadalways arrives perpendicular to the fluke. As a VLA is deeply embedded and alwaysloaded 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 completeembedment 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 usuallynecessary for the pile to be installed at considerable depth below the seabed to obtainthe required holding capacity. Piles are capable of resisting both horizontal and verticalloads.

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 thediameter of the pipe is much larger than for the pile. The suction anchor is forced intothe seabed by means of a pump connected to the top of the pipe, creating a pressuredifference. When pressure inside the pipe is lower than outside, the pipe is sucked intothe seabed. The pump is then removed following installation. The holding capacity ofthe suction anchor is generated by the friction of the soil along the length of the pipeand the lateral soil resistance. The anchor is capable of withstanding both horizontaland 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 mobiledrilling units where they would be routinely recovered. The forces involved in anchorrecovery 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 themooring system. There are different options which can be adopted. This section

briefly reviews the various types and outlines their pros and cons.

Pros:Powerfulmean of

ChainJack

tensioning.Cons:Slow

manipulation.

Most common

PoweredWindlass

method forhandling and

tensioningchain.

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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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Stress Versus Strain Plots for various Chain Grades

0

R4

200

400

600

800

1000

1200

S t r e s s

( N / m m

^ 2 )

R3 - R3S

R4S+ = R5

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

Strain (%)

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

For a strong, fairly ductile (non brittle) material one potentially has a choice as to whatto value to select for MBL. It could either be the load recorded in the test bed when thematerial 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 whichthe load is applied, so it is somewhat variable. Internation Association of ClassificationSocieties (IACS)W22 [Ref. 66] states: “each sample shall be capable of withstandingthe 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 maintainedat that load for 30 seconds”. At the end of the break test, in general the testedcomponent should be scrapped.

It can thus be appreciated that manufacturers have to confirm by physical testing thatthey have achieved the specified MBL and proof load values. In general it would bedesirable 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 achievedshould be considered to be representative of the MBL, not for example the mean or themean minus a number of standard deviations.

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

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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 loadedchain where the maximum stresses are likely to be experienced. Chain links arecomplex, statically indeterminate structures subjected to a combination of bending,shear and tension when loaded. Figure 3-36 gives a fairly crude approximation of thestress distribution in a loaded link. Minimum tensile stress occurs in the outside fibresat the intersection of the curved end with the long axis. Maximum shear stress is about45q away from this axis and on a radial line through the centre of curvature of the endof the link. For chain of low to medium hardness, failure is typically by shear. Ashardness 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 thelink. 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 twocircular cross sections of the straight side of the link. If a link is turned sideways, thelong sides of the link are subject to high bending stresses and the load carrying capacityof 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 byundertaking 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 geometricand material nonlinearities.

From a FE analysis or measurements the value of 1.8P/A in the Crown of the link isfound 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 alink. 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 theresidual stresses were negligible. Still it would be useful to have more data availableon 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 istypically analysed when working under a particular loading boundary condition.

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W e a r a n d f a tig u e

4

CONTEXT SETTING - HISTORICAL INCIDENTSAND THEIR SIGNIFICANCE

So far the modern (say post 1995) Floating Production Industry has not made headlinenews after a spectacular mooring failure resulting in a unit breaking completely free ofits moorings and risers. However, a review of some of the more significant mooringfailures seen over the last few decades shows that there have been serious incidents inthe relatively recent past. Given the substantial increase in the number of FPSs andtheir increasing age, the probability of a future incident does increase. Hence thissection is included to set the context of mooring problems and to try to help to guardagainst 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 operatinghistory based on drilling, accommodation and production units. Semi-submersibleshave relatively good motion characteristics compared to mono hulls (ships). It will beinteresting to see if mono-hull mooring systems suffer from greater degradationcompared to semi-sub mooring systems. Overall, it is important that the lessons learntfrom 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-termmoored system must be able to withstand for possibly in excess of 20 years. At the endof 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 worthconsidering that there are not many mechanical systems, which after 20 years of harduse can still be expected to meet their original design specification.

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

H i g h e s t T e n s i o n s

C o r r o s i o n

I m p a c t & A b r a s io n

B e n d in g & Te n sio n

H i g h e st Te n s io n s

C o r r o s i o n

I m p a c t & A b r a s io n W e a r a n d f a 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 thechain comes in contact with the sea-bed at the end of the catenary. It is at this pointthat most cyclic movement occurs and increased stresses may be encountered due tomomentum 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 thismovement, if the chain is studded, will occur if the studs are able to move. When thestuds 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 removingthe corrosion products and exposing a clean surface. As the process progresses, the rateof corrosion will become higher. This may also be enhanced by crevice corrosion inthe 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 theearliest use of a semi submersible as a production platform – see Figure 4-2. Theconverted drilling rig “Transworld 58” was renamed “North Sea Pioneer” and wasmoored in 79 metres of water. Multiple steels risers were used, since at that timeflexibles were not considered to be sufficiently developed. The risers had to be pulledduring 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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4.1.3 Fulmar SALM Breakaway

The first Floating Storage Unit (FSU) in the North Sea was installed at Shell’s Fulmarfield in 1981. The converted 210,658 dwt “Medora” was yoked by the bows to anarticulated 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 themooring 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 inFigure 4-5.

At one stage the Fulmar SALM was freely drifting in the North Sea with the anchorcolumn nodding up and down as the ship tracked across the sea-bed. It is understoodthat the 3,700 tonne mooring column made tracks in the sea-bed every time it came incontact with it. Apparently the column made a seabed depressions each side of theForties 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 collidedwith 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’sUKOOA report. Overall both incidents illustrate the importance of not beingcomplacent 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 asfollows:

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 completeFSU was replaced by another vessel.

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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 rarelycome into port for repairs. Figure 4-6 illustrates a typical lightship mooring. Althoughlightships are much smaller than FPSOs, it can still be informative to learn from theconsiderable 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 waswhere it left the ship, otherwise known as the “nip.” Here a length of canvas waswrapped 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 atthe “nip”. Also swivels were introduced in the mooring line to reduce the chance of thecable knotting or kinking.

Figure 4-7 shows the “North Carr” Lightship, which broke free from her moorings in1959 and was free drifting while fully manned. This failure led to an ultimately tragicrescue operation. The left hand side of Figure 4-7 shows the links that failed in thegrounded line section. The right hand side shows a link that failed on a North SeaFPSO in 1999. As can be seen, there is a certain similarity between the two failuremechanisms.

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

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

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4.3 “Petrojarl 1” Multiple Lines Failure (1994)

The “Petrojarl 1” FPSO (see Figure 4-11) experienced multiple line failures whileworking on the Hudson Field approximately 60 miles north-east of the Lerwick in theShetland Islands in January 1994. “Petrojarl 1” was subject to 50 to 55 knot NW windsand lost two lines at the same time after being hit by a 20 to 25m high wave. Overall 4out of 8 lines broke over an 8 hour period (lines no. 2, 3, 4 and 7 parted). After theinitial failure production was shut down and the vessel kept on station using herthrusters and the remaining mooring lines. “Petrojarl 1” was never off station andstarted reconnecting mooring lines the next day, personnel were not evacuated. It isworth noting that “Petrojarl 1” had the option of quick disconnection of the remainingmooring lines and risers [Ref. 23]. Planned riser disconnection is not possible for themajority 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 whenhit by a steep wave

4.3.1 Points of SignificanceThe 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 aroundabout the same time to a number of mooring lines.

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

4.3.2 Overall Message from the Case StudiesEven 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 outthe remainder of this report. In general it is clear that a great deal can be learnt fromthe case studies which it is believed is highly likely to be relevant to many of the FPSunits operational in the world at the present time.

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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 areranked as safety critical risk category 1 which is the highest category [Ref. 23].

Y

Z20 m

_ _ _ _ _ _ _ _ _ ;

Figure 5-2 – Illustration of Riser “Stretch” After Loss of Position Following MooringLine 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 failureinclude the following:

Design: the presence of a systematic weakness in the mooring system willapply 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 overtime.

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

Mooring system technology continues to change as operations move into deeper waterand 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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Item Calculation Value Notes

2 x 50,000 AssumingDeferred Prdn x $25 § £1,470,000 1.7$ to £1

(2+2) xDSV £70,000 § £280,000

Heading (2+2) x 2 days mob /control tug £15,000 § £60,000 demob

2 x (2+2) x plus 2 daysAHTs £15,000 § £120,000 diving

£1,930,000

Total §

£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 fieldspecific depending on operating costs, etc. It has been estimated using the followingtypical 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 deliveryincluding all appropriate costs (depreciation, variable lifting and transportationcosts, 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 orrecovery 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/(1.1 n)

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

Deferred production cost in 20 years = 35 x 1/(1.1 20-7) § $10/barrel

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

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

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6

HANDLING, TRANSPORTATION/TRANSFER ANDINSTALLATION

6.1 Transportation/Transfer

Mooring lines are not simple items to transport due to their length and weight. Anydamage to lines during transportation of transfer can have serious implications for long-term mooring integrity. Manufacturers typically have detailed instructions fortransportation and transfer of their products and these instructions should be followedto 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 ropeswith careful level winding and proper back tension when the ropes are installed on thereels.

During transportation, transfer to installation spools and installation of sheathed wirerope, 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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It will be interesting to see if, over the respective field lives, the “dog legs”/wavy linesare pulled straight or not, and this should be monitored during annual ROV surveys. Ifstraightening occurs the implications for mooring line tensions and fatigue loadingshould be re-evaluated. If Dog Legs are still present at the end of the field life, thiscould indicate some conservatism in the design process, particularly if during this timethe 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 thelines. 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 spiralstrand 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 developedis approximately proportional to applied tension and wire rope diameter. For anordinary lay six strand steel independent wire rope core (IWRC), Bridon Ropes quotethe following expression for torque developed under tension.

Torque 07.0 u Diameter u Tension

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

below.

A u RotationTorque 085.0 u Diameter u Tension

Length

Awhere 000531.0 u G u Diameter 4 187.0 u Tension u Diameter 2

NewtonG 000,75 2mm

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

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

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

x Six (or eight) strand wire rope is not torque balanced. This means thanwhen an axial tension is applied, torsion is developed in the line. Thegreater the tension, the larger the torsion.

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

x 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 strandwire it can easily become damaged – see Figure 6-7.

x Polyester rope has a low torsional stiffness, due to the small diameter ofindividual fibres. There is little tendency to develop torsional momentsunder tension.

In the design of mooring systems, consideration must be given both to the interaction ofthe individual components in the operating condition, and to the implications of thisduring installation. It is very important when deploying chain that no twists should beincluded, 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, thismay result in the twisting of adjacent components. Each line type has different issuesassociated with the imposition / release of torsional loading.

x Where six or eight strand wire rope is subjected to dynamic axial loads withno torsional restraint it will rotate. The combination of tension and rotationis much more subject to fatigue than tension cycling with ends restrained.There may also be issues associated with the “whirling” of heavy fittings oradjacent chain segments increasing damage rates.

x The performance of chain when subjected to torsion plus tension is not wellunderstood. Where line tension drops below a limiting value there is some

possibility of knotting of the chain, which will reduce strength and fatigueresistance. Under significant tensions chain is able to accept small levels ofrotation without apparent damage.

x Spiral strand wire rope is both relatively stiff in torsion and sensitive todamage when twisted. This damage occurs due to slippage between layersof (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 awayfrom 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 asignificant impact on their performance.

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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, inline 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 underquite 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 theintroduction 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 thatillustrated 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 mooringlegs 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 certaininstances 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 ofanchor points prior to the arrival of the FPS. Separation of the installation programmeinto discrete segments reduces the vulnerability of the programme to weather windowsand removes these operations from the critical path.

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Deploying an anchor pile, chain, spiral strand wire or polyester rope as one operationcan be problematic, unless a high specification construction vessel is employed and

great care is taken. Potential difficulties include:

x Risk of rotation, possible interference and damage

x Difficult to control simultaneous lowering of multiple handling systems

x 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 thesystem. Assuming a reliable subsea connector is available its use may help withrespect to possible mooring line repair operations which may be needed at some stageduring the field life. It is important, to minimise relative rotation and wear, that theweight per metre of the connector should not be too much higher than that of themooring 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 projectscompleted in the Gulf of Mexico, which have used either spiral strand wire or fibreropes. Very useful experience has been gained form these projects. This sectionattempts 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 directionwhen it is tightened up. Cases have been reported of suction piles rotating as they aresucked into the sea-bed, which can be problematic.

Spiral Strand Wire

The key watch points are:

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

x 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:

x Large diameter ropes, have a large storage volume requirement.

x Multiple spooling operations from storage reels to installation winch arenormally required.

x 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 sheathedspiral strand wire” [Ref. 26].

At present it is customary not to allow polyester rope to come in contact with the seafloor 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 nolonger necessary [Ref. 26] but at present it is customary to adhere to and this willimpact the installation procedures.” Balmoral Group Norway’s experience withMODUs and fibre ropes indicates that this may not be required. However, it is stilldifficult 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” forinstallation including any special considerations, e.g. handling of polyester ropes, suchas:

x Limits on twist

x No sea-bed contact

x Acceptable means to handle and stopper

x Temporary storage and transport requirements

x Contingency measuresPast projects have successfully utilised a “management of twist procedure” to identifyhow 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 messengerline 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 polyesterropes jacket during the manufacturing process.”

Petruska reports [Ref. 26] “Installing a polyester mooring system is similar in manyways to installing a sheathed, spiral strand wire system when using similar/identicalinstallation vessels, but a few differences do exist. For example sheathed, spiral strandhas 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 perfectlytorque balanced while polyester ropes can be made to be torque neutral. On the MadDog project two complete twists (i.e. 720º) per mooring line were permitted for thefibre rope.”

Although polyester weighs much less both in air and in water, it does take up morevolume, 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 differentcategorisations namely:

x Manufactured length,

x Installed length at the specified pre-tension,

x Lengths expected at various phases during the installation.

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

Common practice calls for polyester to never come into contact with sharp edges, highheat or steel work wires. It is vital to ensure all equipment free of sharp edges andwhere necessary to use special padding material such as “burlap” or “lamiflex” tofurther 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 ofservice. 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 ormaintenance operations. Hence a single chain windlass located at one position on theSpar deck with fairleading access to the six mooring stations was assessed to besufficient for pre-tensioning and mooring line adjustment purposes if required. Thissingle chain windlass was integrated into the topsides rather than at a dedicatedwinching deck as on previous spars. To reduce the necessity of future line lengthadjustments, some of the fabrication stretch was removed as illustrated below. Thisrequired application of a tension level of 40% of the MBL for 1 hour, namelyapproximately 500 t. The geometric amplification provided by this means seems to becapable of achieving such a tension. It appears that this method of tensioning up thelines is not very precise and there must be a danger of increased dynamic loading of thetensioning tow line due to tug motion/changes in tow line angle. Hence it will beinteresting to see how such lines perform in situ.

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Figure 6-9 – Pre-Stretching Polyester lines During Installation to Minimise theRequirement 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 lamiflexsheeting and tarpaulins. Also there should be no welding or flame cutting in thevicinity of fibre rope. Hence there may be a need for bolted clips for sea fastening therope reels to transportation cradles.

Fibre Rope Connectors and Thimbles

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

Such connectors need to be designed to simplify offshore lining up of pins. Forexample 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 plateswhich can cause problems with alignment and getting the pin back through especiallyat 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 coatingaround the eye of the polyester splice is manually applied. Also when spreading theeye of the polyester splice to insert the thimble, tearing of the polyurethane would oftenoccur in the crotch region, thus either special care/an improved procedure is required orthe polyurethane needs to be reinforced.

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6.3.3 Anchors

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

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

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

x The first location should be the anticipated anchor landing point.x The second location should be the predicted final anchor position.

In certain instances only limited borehole data may be available. In such cases it makessense to be on the conservative side when selecting the size and weight of the proposedanchors. Anchor steel is relatively cheap compared to the day rate of installationvessels!

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, duringinstallation, the length of all the mooring line sections was carefully noted on the basisthat 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, whichhave a much harder life than an anchor which sits deep into the sea-bed. Still given thatfield lives can be extended and that high quality coatings are available, it would seemlogical 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 theanchor manufacturer’s client.

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7

CORROSION, FATIGUE AND WEAR (CASESTUDIES)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 some19 years.

It is also worth noting that the ‘Buchan’, ‘Amerada Hess 001’ semi-submersibles andthe ‘Brent Spar’ have also seen long deployment periods. Some of the experiencewhich 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 ofdriven anchor piles and 92mm R4 studded chain made in accordance with the newDNV standard to avoid brittle failures. The chain, when new, had a minimum breakload (MBL) of 853t MBL. In addition, the FPV has 4 x 39 tonne maximum nominalthrust azimuthing thrusters, which are used in storm conditions to reduce mooring linetensions.

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

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

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Chart of the FPV Mooring System

N o r t h

i n g

6456500

6456000

6455500

6455000

6454500

6454000

6453500

Kenter links

Touchdown

Missing orloose studs

D-shackles

Pile 1+2.7%

Pile 2No mea surements

Pile 3-1.9%

Pile 4+11.6%

Pile 5+7.5%

Pile 6No mea surements

Pile 7+33.5%

Pile 8-25.7%

563500 564000 564500 565000 565500 566000 566500

Easting

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

Historically, Balmoral’s mooring lines were inspected and the studs pressed every 5years on the back of an AHT. In 2001 one of the most heavily loaded windward lineswas recovered and taken to Haugersund for detailed inspection by Chainco. Everyother link was examined. Just one crack was discovered on the outer shoulder of asingle 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 thechain locker on board the FPV. On this basis DNV accepted Welaptega Marine’s (seeSection 18.4) in water ROV inspection for the other lines, rather than inspection of eachline on the back of an anchor handler.

However, in November 2002 a leeward line broke. Despite a drop in the reportedtension 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 optionwas a partial line run out. The break was only confirmed when the line was pulled inon the chain windlass and a ROV saw the chain end emerge from the mud. This hasdefinite 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 inthe design process. This section reviews the existing guidance which is available inmooring design codes/recommended practices and then compares the specified valueswith what has been recorded in the field. It is worth noting that some earlier mooringsystems were designed with no corrosion allowance. This ties in with what wasspecified 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 areduction in their capacities, such that they no longer meet their allowable loads. Insome 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 termFPS moorings. API RP 2I has universal allowable reductions in chain diameter (seeSection 7.5.3). These may not be appropriate for a long term FPS which does not havean inbuilt allowance for corrosion and wear. In such cases a new evaluation of theworn chain break strength should be undertaken. However, as is discussed in Section7.3.3 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 thesplash 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 asignificant increase compared to other codes.

API RP 2SK Section 3.1.2 states the following “Protection against chain corrosion andwear is normally provided by increasing chain diameter. The allowance in chaindiameter for corrosion and wear is a complicated issue that still requires significantresearch and service experience to address. Currently industry practice is to increasethe chain diameter by 0.2mm to 0.4mm per service year in the splash zone whereoxygenated water tends to accelerate corrosion and in the dip or thrust zone on hard

bottom where heavy corrosion takes place.”

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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 linefailure. 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 laboratorywhich 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 linkswas 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 thethrash 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 inneredge of an adjacent link seems to be occurring (see Figure 7-6). It is also worth notingthat the chain had very loose studs, hence it is possible that contact between the crownand the stud is occurring. However, there was no particular evidence on the stud itselfof 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 ofthe Links

Another example of how the dynamic action of a moving link may cause damage to anadjacent item is shown in Figure 7-7. This photograph shows the beginning of a failureof a small hanging shackle which attaches an excursion limiting weighted chain sectionto the main links of a FPSO mooring line. The failure of the hanging shackle pin islikely to have been caused by the dynamic pinching action of the adjacent link plus thegeneral 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 FPSOMooring Line

When a chain is subjected to an applied load it is subject to a complex combination oftension, bending and shear loads. A finite element derived indicative stress pattern fora loaded link is shown in Figure 7-8. In this plot the highest stresses areas are colouredred. Comparing Figure 7-8 with Figure 7-6 shows that the area of apparent grindingdamage approximately corresponds with one of the areas of maximum stress (see also3.3.3). Hence damage in this area could result in a relative rapid reduction in break testcapability. Another related factor here is the effect of corrosion pitting which in certaincases 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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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 linkof studded chain and the bow of the shackle goes through the studless chain. Based onnominal or typical dimensions significant wear appears to have occurred at the bow ofthe shackle with the bar diameter down from 170mm to 158mm (12mm) a majorreduction 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 manufacturingare 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 theinter-grip area may well not be known. As chain is manufactured it is bent around ananvil 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 anapparent maximum in field combined wear/corrosion of (142 – 134.5) 7.5mm over lessthan 7 years which at 1.07mm/year is high. So far the apparent wear and pittingcorrosion seen on this chain has been 3.6 times (1.07/0.3) higher than was allowed forduring the design process.

Based on the nominal diameter of the studded 137mm chain this gives a maximumcombined wear/corrosion of (137 – 132) 5mm over less than 7 years which at0.71mm/yr is also in excess of what was allowed for in the design process.

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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 areassuch as ballast tanks – see Figure 7-13. Unconfirmed rumours have indicated that SRBmay 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 believedthat the concentration of SRB is higher and this is believed to have caused somedifficulties 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 inwarm oceans. Deep isolated pitting is a text book classic example of SRB attack. Thusmicrobial induced corrosion has potential implications for floating production units inthe tropical oceans. SRB are anaerobic and can develop in a < 1mm thick layer ofslime. These bacteria can cause severe corrosion by accelerating the reduction ofsulphate compounds to corrosive hydrogen sulphide. Concern has also been expressedabout the use of high strength mooring line steel in high H 2S environments as it maylead to hydrogen embrittlement. This can also be affected by the amount of cathodic

protection being applied (see also Par Ohlsson paper, 3 rd Int. Offshore MooringSeminar [Ref. 5]).

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

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Vicinay, in conjunction with fracture mechanics, metallographic and materials scienceexperts 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 mayreach 30 years. An example of such a project is the Belanak offshore liquefied

petroleum gas (LPG) FPSO facility offshore Indonesia. This hull has been designedand built to last 30 years without the need for dry docking and all mechanicalequipment has been specified to last for this period. Such a long design life presentsreal challenges for a system which is exposed to continuous wear and corrosion, yet atthe 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 DesignConsiderations 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 fromother sources. In summary the US NRL’s test results indicate that a corrosionallowance of 0.2mm per year on one side should be sufficient for compensating theactual corrosion damage. This gives 2 x 0.2 = 0.4mm/year on diameter which ties inquite well with the existing codes. However, this is lower than the North Sea referencenumber 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 beenneglected. 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 beexpected year after year, the effect of wear is expected to be significant. Hence it is feltthat 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 seenlong-term deployments in different geographical locations.

The design of the surface floating facility, the type of mooring and metocean conditionswill affect wear rate. For example in 1982 4.5 inch diameter U4 grade chain on aCALM 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 rollstiffness axes and surge stiffness axes. However, this incident shows that acceleratedwear can be a real issue.

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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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An example helps to illustrate the difference between the two approaches. Take a chaindesigned to have a net diameter of 105mm for a 30 year service life. Applying a0.4mm 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 chainwill still have a sound diameter of 117 – (25 x 0.4) § 107mm which would still meetthe original design requirement. However, this remaining diameter of 107 fails the RP2I 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 inconsistencyto 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 tomooring line failure is provided by the failure of a CALM buoy just two months afterinstallation. This was investigated by Shoup and Mueller in their OTC paper 4764from 1984. Although this is a now a fairly old paper, it is still a particularly usefulwork in the respect of surface hardness and wear prediction.

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

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

These experimental tests identified wear rate coefficients which are dependent onapplied 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 thefollowing form:

S 180

· ¸ ¹

. r¦ N 1 1 Fi Fi§ ¨

© § ¨©

I i · ¸ ¹

I i 1 i > @3........ TMV 2i 1

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

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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 potentialimplications 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 importantcriteria for anchor leg design, especially for deepwater systems. Deepwater catenarysystems are prone to anchor chain wear because:

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

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

Catastrophic wear failure of catenary anchor leg lines (at the floating structureinterface) 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 generatinginterlink 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 itwill be interesting to see if wear experienced in the field may make adopting a twinaxis approach worthwhile.

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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 ofthe tension meters, a carefully controlled Line Payout/Pull-In Test was undertaken. Inthis 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 thistest is undertaken relatively quickly in good weather, it would be expected that thesame tension would be obtained for the same line payouts. However, this was revealednot to be the case in all instances, see for example the plot below for Line Number 11.

Line No11

W i r e p a y o u t ( m

)

195.0

194.0

193.0

192.0

191.0

190.0

189.0

188.0

187.0

186.0

185.0

0.0 20.0 40.0 60.0 80.0 100.0 120.0

Tension (te)

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 andthen 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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At present it is not known how common a problem this could be for other operatingunits. Seized wheels may be more likely on a wire sheave than on a chaingypsywheel/wildcat. Hence, it is recommended that similar Payout/Pull-In tests arerepeated for a number of different ages and designs of Semi-Submersibles. This isrecommended in the HSE’s recent research report 219, “Design and IntegrityMonitoring 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 relativeto azimuth rotations. Hence, as well as checks gypsy wheel checks on free running, theability of the fairlead assembly to freely slew or azimuth should also be confirmed. Ifthe fairleads cannot azimuth freely increased chain wear is likely to occur. In practicethe best way to achieve this in the field may be to examine the marine growth at thefairlead to see if it has been displaced as the gypsy wheels azimuth. If there is noevidence of removal of marine growth it is likely that the fairleads may be seized in theazimuth direction and may also have problems rotating!

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9

MOORING BEHAVIOUR AT THE VESSELINTERFACE (CASE STUDIES)

The design of the vessel interface needs to minimize the potential for wear, corrosion orother forms of degradation. However, in field experience is demonstrating that this isnot always being achieved. This is discussed in this chapter. The key points arerelevant to mooring systems in general, not just to one particular design or even type offloating platform. Although turrets are discussed in detail the key points are relevant toSpars, 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 turretdesigns the chains are stoppered off at the base of the turret – see Figure 9-2. There arealso 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 asopposed to chain. Although there are many different designs, including both internaland 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 anytime throughout the field life. Type b) systems use a wildcat at the base of the turretsimilar 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 beadjusted 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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If the line lengths are never adjusted during the field life this means that the same linksin the thrash zone and at the turret interface will need to withstand the majority of thedegradation. In addition, inspecting lines in situ is more difficult, since the chain isrelatively inaccessible inside the trumpet/chain stopper. It is also much more difficultwith such designs to pick up the chain off the sea-bed to make it more accessible for inwater inspection (see Section 18).

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

On type a) systems the trumpets are typically pivoted about a single axis so as tominimize chain rotation and wear. Since the rotation is only about one axis and thetrumpets are arranged around an approximate circle, the pivoting action cannoteliminate chain rotation for all the lines at the same time. Thus, to minimize wear overa long field life, there may be arguments for selecting a design which can pivot abouttwo 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 onthe bow. Depending on location the weather coming in on the vessel’s quarters mayoccur 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 thechain into the chain stopper. The trumpets themselves may include “angle iron” guidesto ensure that the chain is in the right orientation when it enters the chain stopper. Oncethe chains are tensioned the trumpets have no real purpose unless they are required inthe future for a new chain pull in operation. Interestingly, the pivoting chain stopperdesign which was adopted for the Brent Spar buoy did not include trumpets to helpguide 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 joiningshackle was then used to connect up the chain in the field before the line was tensionedup. If you have a reliable method of connecting up in the field this approach does havesome advantages. For example, the trumpets can be dispensed with and it is also easierto undertake a change out of the top chain section at some stage during the field life ifrequired without cutting the chain. This illustrates the importance of having long-termreliable 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 thechains 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 thatit was possible to shroud the chains where they were rubbing against the weld beadswith a replaceable material (ultra high molecular weight polyethylene (UMPHE)sheeting). This whitish material can just be seen on Figure 9-4 poking out of thetrumpets. 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 chainwear, however, the sheeting needs regular inspection and replacement when it becomesworn or damaged. Hence, this is a solution which is only suitable where access isgood, not for a submerged turret, in a harsh environment.

Figure 9-4 - External Cantilever Turret which experienced Chain wear at the TrumpetWelds 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 minimizethe 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 ROVwhich performs a fly by of the lines. During one of these surveys a slight shadow wasseen on one of the chains at the trumpet interface during the annual workclass ROVchain survey. Unfortunately, the large work class ROV was unable to get close inenough to inspect this shadow to determine whether it was simply removal of marinegrowth 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 andtrumpet 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 tanktest is illustrated in Figure 9-6. Micro-ROVs are particularly attractive for inspectingaround the base of the turret since they can be deployed from the FPS itself rather thanemploying the services of a ROV support vessel. A micro-ROV can typically bedeployed 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 themicro-ROV to be lowered down through. The test of the micro-ROV was successfulands 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 bothleft hand and right hand faces of the chain where it has been in contact with thetrumpet.

Figure 9-5 - Example of the Level of Inspection Detail which can be achieved using aTypical 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 atthe Trumpet Bell Mouth (courtesy of I. Williams)

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6

1

Even with the better image resolution provided by the micro-ROV, quantifying theexact 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 diameteris correct. In addition, it can be seen from Figure 9-10 that the location of the notch isin an area which is subject to significant reduction in bar diameter when a chain isloaded 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 howa notch in the chain would affect strength, a notch was ground into some spare chainlinks left over from the original installation – see Figure 9-9. This link was then breaktested to assess how much the chain MBL had been reduced by the presence of thenotch.

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 RedCircular Infrared Target (courtesy of I. Williams)

Figure 9-10 - Example of Stretched Chain during Break Testing, the Blue Mark Showsthe 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 thatsome of the as installed mooring lines would no longer meet the required mooring linesafety 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 mighthappen could not be reliably quantified. In addition, there was some possibility thatfatigue cracks could have developed due to the regular knocking action which, if

present, would reduce the break strength considerably. At present no technology existswhich can check for fatigue cracks underwater, particularly in such an inaccessiblearea. Therefore, the decision was made to undertake a repair operation to change outthe links going through the trumpets by custom built chain links of the same length asthe existing chain, but made from a larger bar size. In addition, the new links weregiven a special hard cobalt chromium anti wear coating – see Figure 9-11. Furtherdetails 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 ofI. Williams)

9.2.3 Actual Chain Condition after Recovery

It is interesting to compare the actual condition of the recovered compared to itsexpected condition. Figure 9-12 shows one of the recovered links. This figure clearlydemonstrates 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 assome 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 anyhairline cracks, but this was not known beforehand. As well as the wear due to contactwith the weld beads, additional damage was noted along the chain which was lyingalong 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 ofthe pivot point - see Figure 9-14. This means that the trumpet assembly does notautomatically follow the motion of the chain. In fact it is contact between the chain andthe outer face of the bell mouth which causes the trumpet to rotate – see Figure 9-21. Itis this contact, plus an associated sliding/sawing action, which seems to have led to thechain notches.

Figure 9-14 - Turret Arrangement where the Chain Stopper (in red) is Behind theRotation 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 chainstopper (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 thecompliance introduced by the bearing takes out as much of the motion as possible andthe metal to metal contact as illustrated in Figure 9-15 is avoided. It will be interestingto see how much wear is experienced in the field by the designs with the stopperoutboard of the pivot point. It will also be interesting to see what happens to the chainwhich is under low tension from the stopper up to the deck of the FPS – see Section9.2.5.

Implications of Long Trumpets

For chain stoppers which are inboard of the pivot points it would appear that longtrumpets are not helpful after the completion of the installation process. Thus it isrecommended 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 theRotation 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 (courtesyof Maritime Pusnes)

Compatible Surface Hardness

In general achieving compatible chain surface hardness is important for long termintegrity, since it affects wear. Unfortunately, at present chain hardness and wear donot seem to be evaluated in any detail. These factors should be taken account of duringdetailed design, but more work is needed on this area before it becomes part of thestandard design process.

Having the pivot point behind the chain stopper may date back to the original design ofCALM 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 nothave been an issue. Given that a tried and tested working design from CALM buoyswas already available it is not surprising that this detail was incorporated into earlyFPSO 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 ProfessionalDiver’s Handbook” [Ref. 38])

On the subject of CALMs Figure 9-19 shows an Imodco buoy with a rubber castingused to minimise wear at the lip of the trumpet. Thus, it is clear that potential wear inthis area has been an issue for a number of years. Significantly during installation it isapparently 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 twosketches of Figure 9-20. With this design the chain where it runs round the lowerwildcat is under high tension, particularly in storm conditions. With this type of designthe first free link “hinges” on the last link in the fairlead pocket as the chain catenaryangle changes. Thus the chain scrubs the surfaces of the pocket and whelp under highcontact pressures. Hence, over time, both the chain and the wildcat will suffer fromwear and damage – see Figure 18-8 and Figure 18-9. An alternative design is presentedin the lower two sketches of Figure 9-20. In this design the in the motion between thechain and the surface platform is mainly taken out at a horizontal pin which attaches thestopper 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 slackfrom where it runs from the chain stopper to the windlass or chain jack. If the line istoo slack there may well be excessive movement between links as the surface platformresponds to wave excitation. Excessive movement can lead to accelerated wear. Ifwear happens above the stopper and then line is let out a weak point may be introducedin the system. However, not too much back tension should be included since it isimportant 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 thewider 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 appropriateto also include mention of bending shoes. As can be seen from Figure 9-21 and Figure9-22 bending shoes can be used both for wire rope and chain. At present there is littledata available in the public domain comparing the performance of bending shoes toeither wildcats/gypsy wheels or permanently stoppered off designs. It would beextremely 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 vesselinterface.

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 offatigue. 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/ddecreases. Under heavy loads, the rope flattens against the bearing surface, increasingrelative motion between strands and wires. Lubrication and large D/d ratios mitigatethe adverse affects of bending. Minimum D/d ratios are available for different ropeconstructions [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 isthus recommended that Chain should not be tensioned over surfaces with diameters lessthan 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 outlinedin 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 indeep water and hence line dynamics (whipping/fluid drag) will affect tension. In otherwords 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 plannedto 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 chainwill 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 STUDIES10.1 Wire Rope Systems

A number of floating production/storage units’ ropes within their mooring systemshave 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 wirewill be subject to degradation at the fairlead region and in the thrash zone. Hence, ifIWRC wire is used in these locations it will typically need to be replaced after about 8years service – see Table 3-9. Further information on when to discard IWRC mooringlines can be found in Chaplin 1992. Figure 10-1 from Chaplin 1992 [Ref. 43] gives anidea of the type of degradation which IWRC rope can be subject to :

Figure 10-1 – Examples of the Subjectivity Associated with Assessing IWRC RopeConditions [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 socketwas found to have parted from the triplate assembly. An in-water survey showed theline to be in normal alignment, but separated by 36m from the triplate assembly, whichwas still securely attached by the mooring chain to the suction anchor. Inspection ofthe mooring line socket showed the socket retaining pin to be displaced, as one of thecircular 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/StoltOffshore)

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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x

10.2.1 Probable Causes of the Failure

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

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

x quite large relative rotations between chains, the wire and the tri-plateelements.

This resulted in rotational torque being transmitted from the wire socket through theretaining 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 pincannot rotate and the torque must be resisted by these bolts. These bolts either becameloose 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 andallowing it to rotate – see Figure 10-7. The issue of whether or not to allow the pin torotate 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. Thereare a number of possible reasons for the anodes becoming disconnected and, due tocommercial reasons it is not possible to discuss these in detail. However, from amooring integrity point of view the key message seems to be “keep your catenariesclean” – see also Section 10.3. In other words avoid adding anything on to thecatenary, 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 ofService

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General Location of Damaged Shackles

General Locationof ExcessiveWear

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

Wear

General Location ofDamaged Shackles

General Locationof Excessive

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 hasoperated successfully in the North Sea since the later half of the 1980’s. As can be seenit 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 appreciatethat 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 stillinspect the chains regularly. Figure 10-15 shows the extent of wear that can still occurdue to the dynamic motion in the thrash zone. Thus whatever connectors are selectedneed 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 utilisingParallel Chain (courtesy of N. Groves)

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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 duringthe course of this JIP. The line back to the bitter end shackle was whipped out of theturret and fell down to the sea-bed. It was a serious uncontrolled incident which couldeasily have lead to a serious injury or a fatality. There was an added danger of damageto sub sea assets. Again semi sub drilling units have suffered from chain run outs andthus this was not a known failure mode. Figure 10-17 illustrates the damage done toone of the chain gripper chocks.

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

x Raised hydraulic oil pressure to approximately 250 barg.

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

x Opened the stopper and the chain was pulled up by fully extending the liftcylinders.

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

x The chain was lowered and the exercise repeated, but it was still not

possible to engage the lower stopper.x Whilst lowering the tensioner a loud noise occurred and operator thought

that chain was slipping through the tensioner and ran for cover.

x Due to dust from the chain being detected by smoke detectors, a platformgeneral platform alert (GPA) occurred and all personnel were mustered.The FPSO was shut down until an ROV could be mobilized through fearof 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 offabrication. This was a result of further load cases which required a stronger mooringsystem. This was identified when the turret fabrication was well advanced. Thus, withthe positions of equipment fixed, compromises in the design were made. Critical tothese were the relative position of the tensioner to the chain locker spurling pipe whichhad the effect of fixing the size of the gypsy wheel and therefore the number of pocketsin 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 arefar 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 thatthis FPSO is unique in its use of a combined upper gripper and lower stopper assemblyin 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 incidenthighlights 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 dimensionalvariation 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 hadloose 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 expectedsuperior fatigue performance of these kenters, they will still need to be examined in thedry after 5 years service. Recovering kenters on to the back of an anchor handler, sothat they can be dissembled and examined, is a major cost. Since kenters themselvesare not that expensive relative to boat time, it makes sense to replace any kenters whichhave to be recovered for inspection. The replaced kenters can then be examined indetail back on land to evaluate whether there is deterioration or cracking. If this showsthat 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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An important principle of practical design is the scrupulous avoidance of sharp cornersor other "stress raisers" if there is any suspicion of alternating stress. So the cause ofthe failure was the stress raiser. Two independent fatigue analyses were made thatshowed the wheel could not have failed even with the bad fatigue detail. Furtherinvestigations revealed that the chains were not being locked off by the chain stopperswhen the chains were not being adjusted, thus increasing the wave cycling loading onthe wheels. Including the wave and wind tension cycle damage continuously was stillfar from sufficient to explain the failure. Knowing the answer the investigators dugdeeper and added to the fatigue estimate the damage caused by the wheel rotation underthe chain load. The rotation fatigue damage greatly exceeded the environment fatiguedamage and “easily” explained the failures. New wheels without the groove were airshipped to Hong Kong and installed. The windlasses have operated without problemsince then.

It is perhaps significant to note that fatigue damage caused by wheel rotation underchain 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 areinformative 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 operationof a one billion dollar facility, one should make the design “robust”. Thereare many ways to increase robustness. One very effective way, and

practically free in comparison to the consequences, is to remove all stressraisers and all bad fatigue details.

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

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

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

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11 SPARS AND OFFLOADING BUOYS (CASESTUDIES)11.1 Brent Spar Buoy

The Brent Spar Buoy, although now famous for the nature of its abandonment, was asuccessful design from a mooring integrity point of view. It had a 19 year operationallife and minimum wear was found on the chains at the stoppers when they wereexamined when the Spar was cut up in Norway, see Figure 11-4 and Figure 11-5 . TheMBL of the IWRC wire rope was found to have had no loss of strength when breaktested 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 ofShell)

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 inducedhull vibration on Brent Spar does not seem to have occurred, unlike some Gulf ofMexico 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 11-3and 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 thefield, but this meant that a kenter was introduced at the connection. Thus this does notseem to be a particularly desirable solution for a long-term moored FPSO. Still itwould be good to find a way of lining up chain in a stopper without using trumpets andangle 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 kenterconnecting link. Such a failure is not surprising, since standard kenters are known tohave low fatigue lives. There are, fortunately, now new designs of kenters withimproved fatigue lives, but these still do not at present have classification societyapproval for long-term mooring – see Section 10.4.1. In addition, one of the Brent Sparmooring 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 ofShell)

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 themooring system. What is perhaps significant about the FLP is that the trumpets whenthe chains come into the platform are short – see Figure 11-8. In addition, this unit wasfitted with simple, but reasonably accurate inclinometers (see Figure 17-4). MicroROV inspection of such inclinometers, in calm weather conditions, can identify if thelines 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 FORMOORING INTEGRITY12.1 Introduction to Turrets and Failure Modes

Turrets are reasonably complicated mechanical constructions which are subject to thefollowing :

x A long service life with limited opportunity for in depth inspections whiledeployed.

x Regular fatigue loading.

x High storm loading.x Gradual wear of bearings, gripper/locking units, etc.

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

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

Active or driven turrets are not normally at the bow or the stern of a FPSO. Thus suchsystems tend not to naturally weathervane. Hence, the FPSO’s thrusters combined withthe turret’s turning and locking system are used to turn the FPSO so it stays head on theweather. It can thus be appreciated that an active turret is probably more susceptible toFPSO 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 theFPSO being exposed to beam sea conditions. What is significant from a mooringdesign point of view is that FPSOs with turrets are not analysed for survival beam seaconditions. The wave frequency motion of a FPSO exposed to survival beam sea typeconditions will be high and in certain cases this could lead to extremely high mooringline tensions. As well as blackship conditions active turrets can also be susceptible tothrusters 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 athruster in the middle of a storm is undesirable.

Good references for turret behaviour in the field are HSE Offshore Technology Report2001/073 [Ref. 47] and “Turret Operations in the North Sea: Experience from Norneand Asgard A” [Ref. 48].

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x

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

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

x For the passive turret if the bearings fail and the turret seizes up there is adanger of ending up broadside to the weather. A serious failure may requiretalking a FPSO off station to dry dock. Depending on location, even in anemergency it will take several days or weeks to put in place arrangements totake 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 islikely to increase with age. It would be interesting to know what level of

bearing deterioration has been noted when FPSOs have been removed fromstation at the end of a particular assignment. A related point is how quicklythese systems can deteriorate if, for some reason, there is inadequatelubrication.

Active turrets do not utilise the turret turning and locking systems all the time. Insteadthe system is only activated when the turret has absorbed about 7 degrees of twist. Thisis different to passive turrets and hence it will be interesting to see if this results in anydifferent wear mechanisms than active turrets. In actual fact this will be difficult todifferentiate since passive turrets tend to be stoppered off at the base of the turret whileactive turrets have a gypsy wheel arrangement at the turret base. Wear at the gypsywheel may be more similar to that which is typically encountered on a semisubmersible submerged gypsy wheel fairlead.

Recommendation

A check should be made on a typical FPSO to see how great the increases in linetension are if the vessel cannot weathervane and thus has to ride out a storm broadsideto the weather.

12.1.1 Line Tension Behaviour over Time

An interesting question is whether on active turrets the mooring line tensions havedecreased 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 closeto the maximum design values. The line tension has not been found to decrease (orincrease) significantly during the first years of operation.

Fatigue cracking was experienced on the grippers of a Norwegian FPSO at a stress hotspot. 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 x Extremely high x Passive systemvertical load capacity requiring no daily

x Redundant system operations

allowing partial repair x Promotes passiveor substitution weathervaning, hence

x Stable turret position suitable for vessel withlimited or no thrusters

x Minimum wear onswivel

x Less risk of humanerrors

x Wide fabricationtolerances

x Adapts to vesseldeformations, hence

promotes a centralturret position withminimum riser loads

Disadvantages x Active turret turning x Non redundant systemsystem needed (failure leads to

x Daily turning “Stuck Turret ”)

operations x Greater wear on swivelx More frequent

maintenance

due to frequentrotations

x Risk of excessive twistin case of turning

x Small fabricationtolerances

system failure or faulty x Vulnerable to vesseloperation – possibility deformationof uncontrolled twist

back. This mayhappen if the torquefrom the mooringsystem overcomes thefrictional torque from

x The forward turret position gives riser tohigher riser motions

and increased mooringloads

the bearings.

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 asecondary 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 importanceof moorings it is vital that regular emergency drills are undertaken to keep training upto date.

On one Norwegian FPSO, to achieve optimum ventilation of the vessel topsidesfacilities the vessel is normally orientated against the weather with the windapproaching 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 beconsidered as one inter-related unit. This is somewhat different to a fixed structurewhere 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 anunusually long period of time in harsh environments. The option for dry dockinspection is not normally available and on going production operations may limitwhen and how inspection can be undertaken. Turret or thruster mechanical repairs canhave safety case implications and any repair operation can be difficult and potentiallydangerous. The following extract gives an idea of what can be involved in repairing athruster 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 motorin its entirety. The lifting route involved a 15-foot vertical lift, cross-hauling through the bulkhead hatch with only 90mm clearance in wintersea conditions, lifting over thruster 1 and a lift through an engineeringspace of 90-foot to reach the main deck. Due to these safety concerns, asafer and better method was needed to achieve the overhaul. The eventualsolution was to strip down the motor into manageable pieces, onboard theFPSO, and to remove the rotor and bell housing for repair onshore. Oncompletion of the repair, the rotor and bell housing were successfullyreinstated using state-of-the-art technology from specialist vendors torealign the motor onboard. The entire process was achieved without anydisruption to production.”

Active turrets also make use of computer controlled systems. Issues can arise ofcomputer/software obsolescence. This needs to be taken account of in the

planned maintenance system.

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13.1.1 Difficulties Obtaining Data

Initially it was hoped that offshore personnel would be able to complete the majority ofthe questionnaires. Despite considerable time spent preparing and chasing upquestionnaires and the ease of email communication, it became clear that thequestionnaire 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 particularlydifficult. The problem was not necessarily lack of interest, just a lack of time withoperational issues taking precedence. It is noted that good data could be obtained byvisiting FPSs and auditing the condition of the set up of their mooring systems andreviewing 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 whichwas obtained was in general of high quality (see Case Studies) and is believed to be pofrelevance 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 beento collate data in a similar fashion to the “UKOOA FPSO study” but extending it to theworldwide fleet of FPSOs, Production Semi submersibles and Spars. Mooring

performance will depend on the type of unit considered and the environment which it isexposed to. The following generic types have been considered:

x North Sea turret moored FPSO

x North Sea Semi-sub FPS

x West African spread moored FPSO

x Brazilian deepwater FPSOs (turret and spread moored)

x Brazilian Semi-sub FPS (very limited data received)

x Gulf of Mexico Spar

x South East Asia FPSO

x Special FPSOs e.g. dis-connectable and ice resistant

x 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 resultsobtained from post processing the returned questionnaires. Only statistics where areasonable sample size was acheievd have been reported.

North Sea Turret Moored FPSOs

Lines

Adj

Adjustable Line Lengths

Locked Off50%

Can Beusted

50%

67%

33%

Real Time Offse t Monitoring

Units with

Unitswitho ut

50%

Real Time Line Tension Monitoring

Units with50%

Unitswitho ut

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78%

Line Failure Alarms

Units with22%

Unitswitho ut

Mooring Line Spar es

Units with33%

Unitswitho ut

67%

87%

Existing Repair Procedure s

Units with13%

Unitswitho ut

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It is interesting to compare the average mooring line inspection periods for variousdifferent types of FPS units in different locations. This is illustrated in Figure 13-1.

5

0

1

2

3

4

5

1.21.6

0.5

1.5

2.5

3.5

4.5

Year s

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 FPSCategories

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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/FSUTotal

Incidents

11 10 15 22 10 11 79

Mooring/DP percentage of

FPSO/FSUincidents

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 AccommodationSemis

FPSO’s

N F N F N F N F

AnchorFailure

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 definedas “Problems with anchor/anchor lines, mooring devices, winching equipment orfairleads (e.g. anchor dragging, breaking of mooring lines, loss of anchor(s), winchfailures.”

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 NorwegianSector [Ref. 50]

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NDE’s UKOOA report referred to DNV’s data for 1980 to 1998, which reported 7FPSO/FSU anchor system failures. This gave 0.186 failures per unit operating year orone failure every 5.4 operating years. Hence, it can be seen that the failure rate seemsto have improved somewhat from 1998 to 2001.

0

1

2

3

4

5

6

7

8

9

10

Comparison of North Sea Failure Rates for Different Unit Types (1980 - 2001)

Drilling Semi Production Semi FPSO

Type of Unit

N u m

b e r o

f o p e r a

t i n g y e a r s p e r

f a i l u r e

Figure 13-2 – Historical Failure Rates for Different Types of Units

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14 CONNECTORS AND TERMINATIONS14.1 Background

Connectors and line terminations (e.g. spelter sockets or fibre rope splices) are vitalcomponents in a mooring system, since they are typically necessary to join up differenttypes of line e.g. chain to wire, or to suit manufacturing/transportation limitations online lengths. However, the need for some type of opening and closing mechanismmeans that, to achieve the required strength, the connectors tend to be heavier than thelines to which they are attached. Thus connectors and line terminations tend to be areasof discontinuity on a mooring system with respect to weight per metre and also bendingand torsional stiffness. This is because they are unlikely to flex in the precisely thesame 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 increasein 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 exampleFigure 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 withtraditional 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 changesfor new applications. Hence this section attempts to summarise what connectors andline terminations are available at present. It then goes on to consider what should betaken account of when designing new connectors – see the flow diagram in Section14.3. The section concludes with any gaps in the existing knowledge base andidentifies 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 adouble locking mechanism, such as a nut and locking pin restraining the primaryrestraint system, see for example Figure 14-10.

The following section reviews the type of connectors which are fairly readily availableand 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 chainsconsists of two similar parts a, b, which are adapted to engage laterally andare locked in their engaged position by the grooved piece f. Movement ofthe piece f is prevented by the inclined taper-pin h secured in place by thelead plug i.” [Ref. 52].

The great merits of a kenter are that it can pass through a gypsy wheel in the same wayas normal chain and its dynamic behaviour is very similar to chain, since it is ofcomparable 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 lastquite well for a temporary application. Still assembly tolerances vary in practice, andthus 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 linkchain without the need for an enlarged end links, which would typically be required if anormal shackle were to be used. Enlarged end links can only be added to a chain at aForge so their inclusion reduces flexibility with regard, for example, to trimming chainduring line hook up operations.

The bow of a SJS needs to be trimmed compared to a standard D shackle to allowstudless link connection. To qualify for LTM designation typically a double lockingmechanism for the shackle pin is required, as well as a demonstration of fatigue life. Inaddition, 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 itnormally cannot rotate in the shackle body. Normally when two chain links rotateagainst 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 linkand the shackle, as well as the geometry may be somewhat different. If thecombination is such that this leads to accelerated wear of the chain link, which is ofthinner section than the shackle, then this could lead to early loss of integrity. Inaddition, due to the weight discontinuity it is likely that there will be more relativerotation 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. Inthe case described in Section 10.2, the initial approach adopted to preventing pinrotation was not strong enough and ultimately failed. The solution was to allow thesystem 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 passthrough the shackle body. This is needed to make them small enough to pass throughthe chain links. However, the holes in the H shackle body are round. This allows theoval pin to rotate in the H shackle body. Since the H shackle body and pin areoversized any wear in these components should not be significant. But it is importantthat wear in the attached chain link should be minimised, since when it moves it shouldnot 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 measurementswere 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 forsubsea connectors are discussed in more depth in section 6.2.4. More temporary typesof connectors include Baldt or C connectors and pear links. Sometimes these are “arattling 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 temporaryfixes, unless they are all that is available. Standard kenters are better machined, “fittighter” and are more suitable for a short term repair.

SubseaDesigned to

facilitateConnector

connection &(Delmar)

disconnection

Female Male

Female and Male being assembled

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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-InstalledMooring 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 endsinto the mooring system. The task of the termination is to transfer the predominantlyaxial load in the rope into an engineering component which can be attached to standardmechanical/structural components which form part of the platform being moored.

Nearly all rope terminations depend to some degree on developing radial forces - andthrough them friction - to allow the axial load in the rope to be transferred to anotherelement. The splice is the basic example of this in which, when the rope is placed intension, the geometry of the splice generates radial loads between the rope strands andthese 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 amechanical device.

It is well documented that during break or fatigue testing many rope specimens are seento fail at or very close to the terminations. This is due to the additional stressesintroduced 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 mayhave 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 ofthe large size of typical mooring ropes. An alternative which has developed is the useof the spelter socket (see Figure 14-7) in which the rope is inserted into a metal collarwith an internal conical hole. The wire rope is cleaned and teased out to form a brushwhich adopts the internal conical space of the termination. Into the cone is poured amolten 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 ofBridon)

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Wire rope terminations or sockets can be either open (Figure 14-6) or closed (Figure14-7).

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. Pottedsockets have the advantage that they can be applied in the field if necessary without thecomplications 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 ofwire 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 astrong bond to the fibre material and socket. Conventional wire rope sockets have beenused successfully on small aramid ropes.

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Although epoxy potting has been used for some small size fibre ropes it has not provedeffective 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 therope. Solutions have been proposed in which the rope is divided into componentstrands each with its own potted termination but so far the complexity of this approachhas been a major obstacle to its use.

It is important that, when being prepared for potting or speltering, a rope must beaccurately set so that the termination is not at an angle to the axis if the rope. If thishappens the rope will be subjected to a degree of bending when the load is applied andthis can seriously weaken the capacity of the rope. This effect is particularly apparentwhen only a short specimen of rope is being terminated as in such cases the limitedlength of the rope means that the uneven loading over the rope cross section has lesschance 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 preparingshort 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 oftenapplied. This is not really appropriate and requires further consideration on live

projects.

The Bend stiffener and attachment mechanism also needs to be suitably designed, seefor 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 alsoimportant 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. Thereis a large degree of experience available when considering terminating large diameterfibre mooring ropes with eye splices. Other techniques (Grip and Potted) are much lesswell documented. A splice in a polyester rope has been shown to have an efficiencyapproaching 1.00, depending on the quality of the splice. It should be noted that thecertified 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 describemodelling of splices (see for instance Ref. 67) and recent offshore projects in the Gulfof 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 abovethat of steel wire rope at normal working loads.

For large diameter synthetic fibre ropes under long term cyclic loading the only verifiedtechnology 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 atsingle point mooring terminals. This type of connector is, however, described asmaking rope handling particularly cumbersome and awkward [Ref. 68].

To-date most offshore experience of large fibre mooring ropes has relied on this type inwhich 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 documentssuch as Ref. 69. The thimble diameter should be large enough to develop the best axialtension and fatigue strength while minimising abrasion and wear as the stretching ropeslides against the metal of the spool. In order to minimise this problem the splice eye isoften 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 thimblefrom falling out. However, during over-boarding when there may low line tensions andeccentric loads on the connection care must be taken to stop the line slipping-off thethimble and being caught on the shackle instead.

It is important that the fitting between the eye and the spool is tight enough so that thetwo do not become separated. This is described as being most likely to occur duringrope handling when the rope is slack.

This is often achieved through encapsulating the thimble in polyurethane. However ifthe splice is provided with a permanently fitted hard eye in this way it means that thereare additional problems when handling the rope on its transportation and deploymentspools as the thimble must be prevented from abrading and damaging the rope on thespool.Various novel terminations are currently being proposed and evaluated. These seek toimprove the efficiency of terminations for very large ropes by splicing the sub-ropesindividually to themselves to create a number of eyes. These are then supported onmultiple pins. High performance materials (e.g. titanium or super duplex) are used inorder 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 onapproaching the subject with a blank piece of paper. The flow chart is also generallyapplicable for the design of terminations. Comparing this flow chart with present daydesign practice shows that the following:

x A wear analysis is typically not undertaken

x The dynamic motion of the connector is typically not evaluated

x Calculations are not typically undertaken to size locking pins based on highline tensions and frictional forces

x Electrical isolation needs to be considered early on in the design process

x Inspection is not given a high priority during connector design.

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NO

Could any existing

NOYES

UNSATISFACTORY

YES

designs be used?

Asses the pros &cons of the existing

design & decide

whether to proceedwith modifications?

Develop a Design Brief specifying strength,fatigue life, installation weight, material

properties etc

Obtain Client written approval of Design Brief& Class agreement in principle

Requirement to join two lines

Assess the ease of deployment, includingconnection/disconnection & the likelihood of

unintentional disconnection

Identify what is special about the newapplication & propose a new design

Quality Plan for design & manufacture todescribe activities to be performed, frequency

and type of inspection/tests, criteria to be met aswell as give reference to applicable controlling

documents

Submit Quality Plan for Class Approval

Figure 14-8 - Connector or Termination Design Flow Diagram - Initial Phase

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NO

Calculations

- Codes

Factors Identified?

- Past Observation- Calculations

- Hand/Simple

Approval

& Long Term Insp

NO

Wear Assessment

- Proposed Methodology- Justification- Past Observation- Guidelines

Fatigue Life Assessment

- Suitable S-N Curves- Stress Concentration

- Physical Testing- Hand/SimpleCalculations- Tension/TensionAssessment- Tension/BendingAssessment- Cumulative DamageEvaluation

Corrosion Assessment

- Avoidance e.g.Anodes- Allowancee.g.Corrosion Margin- Physical Testing

Strength Assessment

- Finite Element Analysis- Material Testing- Physical Testing

Commence DetailedDesign Process

Manufacture in accordancewith Quality Plan & Class

Society inspections

Test Connector as perQuality Plan

Documentation to bestamped with Class

Issue Recommendationsfor Connector

Transportation, Installationection

Finalise Design Reports &Drawings; issue to Class

Society & Client

DesignIterations

Successful?

YES

Figure 14-9 - Connector (Termination) Detailed Design Flow Chart

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14. 5 Detailed Design Guidance

There are numerous different types of mooring line connectors depending on whetherchain, wire or fibre ropes are being connected. Operational experience from a numberof floating production and drilling units has shown that failures quite often occur atconnectors. In certain instances the connectors have failed by coming undone whentheir locking mechanisms have failed, see Section 10.2.

To ensure the long term reliability of a FPS mooring system it is important that thedesign of ALL the proposed connectors in a mooring system should be carefullyreviewed. 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:

x Try to minimise connector weight to avoid increased rotation at each end due toan abrupt change in weight per metre of the mooring line.

x Avoid placing connectors in the thrash zone.

x Allow shackle or spelter socket pins the ability to rotate.

x Add marks on connectors so that any wear can be measured.

x Ensure connectors have compliance in all required planes of motion – see below.

x Match material characteristics to minimise wear.

x Pin locking devices need to take in to account applied loads and friction developedlever arms.

x Secondary locking devices should be provided which are capable of withstandingthe full anticipated loading in case the primary device fails.

x Sharp edges where any pin is stepped down to the locking nuts should be roundedto minimise the danger of cracking occurring.

x In general rounded rather than chamfered edges around the edge of the shackleshould minimise damage if contact occurs with chain links.

x 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 besimilar to link to link contact.

x Thought should be given on how to handle the connector given its weight.Welding lifting eyes on to it should be avoided.

x 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-bedand the sea-bed takes up the weight, the tension may drop down to zero. Hence if youhave 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 thelines are likely to go slack at any time.

Chain, wire and fibre rope can all rotate in numerous planes. However, most connectorshave limited compliance and it is thus important to confirm that, where they are placedon a mooring system, they can allow the predicted motion without resulting in lock upand 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 therequired compliance in two planes and then the “V” in the “X” shackle was designed tosuit, including a contingency factor, see Figure 14-2 and Figure 14-10.

When designing a connector the most appropriate proof stress should be assessed whichwill give a good fatigue life – see Section 14.5.

Figure 14-10 – Illustration of a Purpose Designed connector allowing limitedcompliance in Two Planes

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Figure 14-11 - Example of a Dynamic Analysis to Estimate the Angle for the “V” SlotSize on the “H” Shackle

Certain connectors, such as Long Term Mooring (LTM) D shackles, have beenavailable 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 theirinherent elaborate design. Forging is the preferred method of manufacturing mooringaccessories, since it helps to ensure that the items are strong but ductile. Impactstrength is a key element in any mooring accessory design.

The following list details the advantages of forgings versus castings [Ref. 51] :

x Higher strength

x Unmatched toughness

x Longer service life

x Higher structural integrity (absence of internal defects)

x Use of higher design stresses

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x Greater transverse properties

x Increased safety margin (due to high ductility)

x Greater strength-to-weight ratio (lighter parts, reduced sections)

x 100% density (no porosity)

x Higher overall quality / reliability

x Reduced product liability concerns

x More acceptable parts / fewer concerns

x More uniform heat properties (lot to lot, and part to part)

x Directional or isotropic property profile

x More consistent machining (uniform microstructure and chemicalcomposition)

x Better hardness control for abrasion / wear resistance

x Extended warranties more probable on critical part / assemblies

x More versatile processing options and combinations

x 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 andregulations for assessing whether a connector is suitable for a long term mooringapplication. It would be helpful if, perhaps under the auspices of IACS (InternationalAssociation of Classification Societies), that a standard protocol could be developed fordesigning 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. apartfrom 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 ofthe 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 throattype.” Since spiral strand sockets are not D shackles or Baldt or Kenter links it can beargued that it is not valid to assess their fatigue performance using a S-N curve forcommon 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-Ncurves 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 towhich it is connected. Considering the cost associated with mooring failure orintervention, 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 ofa mooring system. Where there is an abrupt change in weight per metre of a mooringline at a connector, greater relative rotation can be expected. This may not be too muchof an issue for the connector itself which may be oversized. However, over the longterm 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 consideredto 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 samplelength of chain is loaded in tension to an estimated break load value which it is held atfor 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 isnominally 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]. Instudded mooring chain proof load is about two thirds of its break strength. For examplefor 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 breakingload is typical.

The proof load concept needs some further refinement for materials, such as certainhigher strength steels, which do not exhibit a particularly defined yield point. Thesematerials initially respond under load with a linear elastic response but this graduallysoftens until the ultimate tensile strength (UTS) is reached. As no yield point can beused 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 a0.1% strain permanent set would result following elastic unloading. Depending on thematerial, 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 toconfirm that the degree of elongation under application of the proof load (stress) is notexceeded.

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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 thestiffness (elongation) of chain and to ensure the studs are ‘fixed’ following heattreatment which otherwise relaxes the initial clamping forces applied. Proof loads aregenerally defined in codes and standards as a proportion of the minimum 0.2% proofstress or minimum UTS combined with the nominal section area.

Proof loading of the chain into the plastic range leaves a small permanent set when theload is removed. The component geometries means this induces locked in residualstresses in the chain and these are compressive at the inner shoulders of the links. Thismeans that applied tensions have to reverse the residual compressive stresses beforetension is induced in these fatigue prone areas and the proof loading may therefore beconsidered to be beneficial to fatigue endurance.

Evidence for this was obtained, inadvertently in the BOMEL JIP. The first two tensionfatigue tests delivered extraordinary results and were halted, without evidence ofcracking, when the predicted lives were exceeded by a factor of around three. Inconsultation with the chain supplier, it was concluded that the chain had been subjectedto an excessive proof load during manufacture. It was noted that such treatment wasallowed under the specification and the practice is not uncommon to stretch the chainwhen it is under-length.

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Amoco (one of the BOMEL JIP sponsors) proceeded to undertake further testing toassess proof loading effects on the fatigue life of chains, in conjunction with theUniversity of Tulsa [Ref. 54]. A range of proof load levels was investigated (up to82% of break strength) and it was concluded that proof loading substantially increasesthe fatigue life and this was attributed to the residual stresses generated. Importantlythey noted that in addition to the level of proof loading, the ability of the material tosustain the residual stresses without redistribution under cyclic loading was anotherfactor affecting the consequences for fatigue life.

A difficulty for high strength (e.g. R4) chain is that the proof stress is cited withreference to the minimum UTS/breaking load. If a batch has a significantly higherUTS (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 specificationmaterial. This means that the degree of residual compressive stress within the linkswill vary depending on the actual material properties. Furthermore with the highstrength steels used for chain, the proof stress to UTS ratio can exceed 0.95, somethingthat 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 consequencesin 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 proofloading is less than anticipated, studs will be more likely to become loose in service.

The above discussion highlights the importance of:

x Developing a more meaningful specification for effective proof loading duringchain manufacture

x Undertaking research (using finite element analysis and physical testing) todefine 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 theminimum break load test because the rate of load application was faster than had beenspecified by the manufacturer’s test procedure. Another connector plate was testedusing a slower rate of load application and passed the minimum break load test.

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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 bendingmoment resulting from the local geometry of the contact between chain link and gypsywheel bearing surfaces. Fatigue issues associated with chain links in gypsy wheelfairleads 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 areoften restricted to links in the catenary, neglecting the reduced fatigue life local to theend termination. One North Sea unit suffered a link breakage at the fairlead, after onlyone 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 damagewith can result from the high stresses experienced by a chain link at a fairlead.

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15.1.1 The Load Mechanism

The load mechanism is related to the eccentricity of thrust lines with respect to the barneutral 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 beincreased where wear of the fairlead moves the contact point away from the end of thelink. The imposed hogging moment is balanced by a counter effect at the other end ofthe link.

The chain links within the fairlead are thus subjected to an out of plane bendingmoment 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 inthe 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 chainJIP – see Section 15.1.2. Fatigue damage (SN) curves and implied stress concentrationfactors 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 ofanchor chains [Ref. 10]. As part of this study work they conducted a series of tests toexamine 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 (seeFigure 15-4 and Figure 15-5). The horizontal link was supported at four points on amounting point which was cycled vertically in order to develop varying tension in thetwo fixed links. The tests were conducted on 54 mm diameter K3 chain with weldedstuds.

Figure 15-5 - General View of Tension Bending Test Rig (protective screens removedfor clarity) [Ref. 10]

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BOMEL monitored the mean and range of the imposed loads in the horizontal link andused strain gauge readings to assess the response of the chain. The result set waslimited 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. Itcan be seen that two of the four hardened bed plates are cracked diagonally oppositeeach other. The wear marks on the plates and on the links indicate that the two whichcracked were more heavily loaded than the other pair. The crack in the link occurredover 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 offlatness in the unstressed link. The initial out of flatness was measured for allsubsequent tests – see Figure 15-8. As can be seen in Figure 15-7 in certain cases outof 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 theshoulders of the link against the fairlead plus of the bend at each end against thecorresponding sections of adjacent links. As a result imperfection in any of the threelinks, or in the fairlead itself, can prevent the link from initially bearing on fourshoulders.

As the link is relatively stiff BOMEL found that the load required to deform itsufficiently that load is transferred through all four bearing points may approach or evenexceed 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 CalculationDespite the limited data set, BOMEL presented a fairly consistent relationship betweentension range and number of cycles to failure. Scatter appeared to be associated withinitial out of flatness in certain links.

A factor on the nominal stress in the link was defined as the local (measured) stressdivided by the nominal link stress.

Fac nom = Factor on nominal stress = Local (Measured) stress/ Nominal link stress

Nominal link stress = LineTension/Area = LineTension /(2 x ʌ x (Bar Dia/2) 2)

Nominal link stress = (2 x LineTension) / ʌ x (Bar Dia) 2

The measured Fac nom value associated with two point bending was 5.2. A lower Fac nom

of 3.6 was measured under 4 point bending. The two point bending Fac nom compareswell with a value of 5.9 derived from the difference between the intercept for thefatigue performance curves for tension bending and for pure tension (all conducted inthe same JIP). The stress factors for a given material can be compared using anexpression of the form given below.

log( A ) sionTensionTen ) log( A ding TensionBen

Fac mding TensionBennom ) 10 u Fac sionTensionTen(

This expression can be re-arranged as follows for a pedagogic understanding :

1 1m Fac ding TensionBennom )

u A ding TensionBen Fac sionTensionTennom )u A sionTensionTen m( (

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 appliedto the in-plane bending stress for a link in the catenary. BOMEL record a factor of 3.7on the nominal stress for this condition. If we use this to convert the DNV values tofactors 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 pocketComparative factor of 9.3 <= 2.5 x 3.7Factor on fatigue life of 0.06 <= 2.5^(-3.00).

DNV 9 pocketComparative factor of 5.6 <= 1.5 x 3.7Factor on fatigue life of 0.30 <= 1.5^(-3.00).

APIEffective 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 curvegradient of 3.36 amounts to an effective stress factor of 1.61, in this case producing acomparative 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 Parameters Note 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 theimpact that this has on fatigue at wheel fairleads. The upper bound factor from API isgenerally consistent with the BOMEL results for 2 point bending, with the DNVguidance appearing somewhat more onerous.

Use of the two point bending factor can be further justified by consideration of stiffnessof a chain link. Even for a relatively perfect bearing geometry (0.8 mm link out offlatness on a machined support bed) approximately half of a load cycle occurs undertwo point bending. For a link with 3 mm out of flatness in the test rig the entire loadcycle occurs under two point bending. Clearly this indicates that the higher SCF isapplicable for fatigue calculations, as reflected in both DNV and API guidance.

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API makes recommendations regarding the design of the fairlead and management ofthe 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 thesystem. Subsequent engineering review of the system indicated that the principalfailures were driven by fatigue damage.

The Girassol offloading buoy [Ref. 55] is a 19 m outside diameter circular buoymoored in approximately 1,320 m water depth. The original mooring systemcomprised 3 x 3 mooring lines. Each line was made up principally of polyester linewith chain sections at upper and lower terminations. It was designed to act as a tautsystem 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 werecaused by a breakage of the fifth link from the chain stopper. The third line failed dueto overload of a section of the polyester line which appears to have been damagedduring installation (see Figure 15-12). The corresponding chain link on the last linewas also found to have suffered fatigue damage.

Subsequent to the first three breakages, failures have occurred in both of the remaininggroups of mooring lines. Clearly the system was subject to much more onerous fatigueconditions 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 beengenerally 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 inducinggreater 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 theresult of a cyclic out of plane bending moment applied to that link. It should be notedthat the geometry of the chain trumpet essentially restrains links 1 to 4 to move with thetrumpet. Rotation between the buoy and mooring line is concentrated on link 5 and to alesser 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. Underhigher tensions a significant inter link friction has to be overcome before this slip canoccur as well as local flattening at the point of contact. These effects result in torsion inthe bar at the contact point, which is represented by out of plane bending in the body ofthe 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 theline 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.

nCalculatio

3 22S D 2S D P TD Z , A , M , P 1.0nom nom nom32 4 22V bnom M u A P TD u 32 u 2S Dnom nom 40.03V Z u T 2 u 2S D u T u 4tnom nom

Notation:

D chain bar diameter (m)

T Tension force (kN)

A Area (m 2)

M Bending Moment (kN.m)

Z bar section modulus (m 3)

V Stress due to bending or tension (kPa)

µ Friction coefficientnom Suffix nominal

b Suffix bending t Suffix tension

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Using this relationship with the DNV B1 curve [Ref. 57] and a limiting range ininterlink angle of 3.8 degrees (imposed by geometry of chainhawse) SBM computed alife to failure of 107 days. This calculation assumed that the full pitch rotation wasimposed on a single link, and that the friction coefficient was sufficient that no slipoccurred up to the limiting angle of 3.8 degrees (amplitude) where the 7 th link touchesthe 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 interlinkfriction driven fatigue can result in very rapid fatigue damage. This mechanismappears not to govern for many mooring systems, though the basic mechanics will be

present for all chains.

holding ahorizontal link

Pivot point

Stopper plates,

of trumpet

Figure 15-17 - Typical FPSO Chain Stopper Arrangement

The requirement for rotation between the end links of the chain was not a result of thecurved chainhawser. As illustrated above, where the stopper is located above theassembly pivot point, rotation of chainhawser is unlikely until the chain contacts the endof 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 Girassolsystem.

i) The nature of and natural frequencies of the moored structure resulted in angularrotations 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 ofsignificant interlinks friction forces and local yielding.

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The relative significance of these is not yet totally clear at present. Due to theindividual stiffness of chain links, large bending stresses can be developed by relativelysmall end rotations. These will tend to be relieved, either by slip or contact with thetrumpet, for larger motions. The proportion of the rotation imposed at a single link maydepend upon the chainhawse design, but this has not been studied. Friction coefficientsfor 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 mooringchain. The first calculation relates to Girassol (high pre-tension and an assumed annualdamage of 1.0 from the failure history). Example 2 relates to real example for a FPSOin moderate water depth and a relatively low pre-tension. Example 3 relates to an FPSOin deep water with high pretension. These calculations are intended to be indicativeonly, it is appreciated that the wave climate, directionality and chain hawse geometryare not represented.

In the following examples the notation listed below is applicable:

D chain bar diameter (mm)

T Tension force (tonnes)

A Area (m 2)

M Bending Moment (kN.m)

Z bar section modulus (m 3)

SCF Stress Concentration Factor

m Slope of the S-N curve

N Number of cycles to failure

N 1 year Number of cycles in one year

V Stress due to bending or tension (kPa)

µ Friction coefficientnom

Suffix nominal b Suffix bending t Suffix tension

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3

Example 1 is a summary of the behaviour of the Girassol offloading buoy.

Example _1, D 81 Tmm 5.123 Te , P 1.0

2S D P TD Z , Mnom nom32 2

M P TD u 32 8 P T nomV 47MPabnom 3 2 Z 2 u 2S D S Dnom

log( N ) log A m 2log( u SCF u V bnom )

Take log(: A) ,46.11 m ,173.3 ge AnnualDama ,1 N 1 year 6 u 10 6

) 46.11 173.3 u 2log( u 47 u SCF log( N 1 year ratio )46.11 778.6

( ))94log(10 173.3SCF 318.0ratio

NB : SCF 7.3 u SCF 18.1ratio

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).

Log 10 N = 11.32 – 3.173 log 10('V nom)

The report expression is:

Log(N) = logA –mlog(2 x SCF x V bnom)

M = 3.173 is the SN curve gradient. 'V nom is the nominal stress range in a link duringfatigue testing. This has been set to be equal to 2 x SCF x V bnom . The 2 takes intoaccount that the link can move both clockwise and anticlockwise about an axis throughthe 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 fatiguemore rapidly (logA increases by 0.301 based on standard fatigue texts for in air andcathodically 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.

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N1 year = 6 x 10 6 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 10 6 cycles. This is a crude

approximation.

The annual damage amounts to (6 x 10 6 cycles)/Inv. Log(11.46 – 3.173 x log(2 x 47 x0.318)) = 1.0002, which means the fatigue life is consumed in less than a year. This isnot too different to what happened in practice on the Girassol buoy

Example _ 2, D 120 Tmm 60Te , P 1.032S D P TD

Z , Mnom nom32 2

M P TD u 32 8 P T nomV 10MPabnom Z 2 u 2S D 3 S D 2nom


Take log(: A) ,46.11 m ,173.3 SCF ,18.1 N 1 year 6 u 10 6

18.1log( N ) 46.11 173.3 u log( u 2 u )10

7.3 N 10 91.8

N ge AnnualDama 1 year 007.0

N

Example 2 results in a fatigue life of approx 143 years

Example _ 3

, D 114 Tmm 143Te , P 1.032S D P TD

Z , Mnom nom32 2 M P TD u 32 8 P T nomV 27MPabnom Z 2 u 2S D 3 S D 2

nom


Take log(: A) ,46.11 m ,173.3 SCF ,18.1 N 1 year 6 u 106

18.1log( N ) 46.11 173.3 u log( u 2 u )27

7.3 N 10 54.7

N ge AnnualDama 1 year 17.0

N

Example 3 results in a low fatigue life of approx. 6 years. This is potentially asignificant and worrying result which merits further investigation.

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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 providingguidance on the calculation of tension-tension (T-T) fatigue.

API offers some indication of fatigue life reduction factors taken from experience ofoperations 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 itscomplexity. 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 examinefatigue of wire ropes under bending tension conditions in 1988 [Ref. 58]. These testswere carried out on a 40 mm diameter six strand rope with an independent wire ropecore. A test rig was developed for the purpose - see Figure 15-19. The set up permittedthe rope to be cycled both with respect to tension (load amplitude) and movement overthe 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 atravel of 25% of the lay length.

ii) The mean tension is the next most significant parameter in determining the rateof 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 thedominant source of fatigue for tension bending.

The requirement to consider a loading source other than the tension range is reinforcedin OTH 91 341 [Ref. 59] where it is concluded that although the tension-tension fatiguelife is driven by the load range, the bending-tension fatigue life is governed by themean load and bending over sheave (BOS) behaviour.

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Figure 15-18 – Illustration of Wire Rope Failure Modes (courtesy of Bridon)

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OTH 91 341 [Ref. 59] introduces a useful distinction within B-T fatigue between anupper bound T-T life and a lower bound Bending over Sheave (BOS) value. T-Tfatigue damage rates would be derived from the load range history of the mooring lineand 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 sheaverotations.

It is possible that the two mechanisms can be considered independently. This woulddepend upon the potential for bending length due to wire stretch under the tension loadrange. It is understood, however from OTH 91 that the BOS damage rate would bedominated by mooring line to vessel rotations, justifying independent treatment of BOSand T-T fatigue.

15.3.4 ConclusionsA large body of research has been conducted toward understanding bending tensionfatigue of wire ropes. But no generally applicable quantitative guidance is offered byDNV or API on this subject.

The fatigue process and loadings associated with bending tension appears to be wellunderstood. Substantial test work has been carried out permitting the definition ofload-cycle curves for various configurations.

Therefore, the development of specific design guidance for the estimation of bendingtension fatigue for offshore mooring systems appears to be feasible. It is recommendedthat 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 incombination wire/chain systems increase.

Figure 15-19 - The 1.0MN Wire Rope Bending-Tension Fatigue Test Machine

[Ref. 42]

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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 anextension 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 becalculated 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 associatedwith the Girassol buoy. It is recommended that within design of the mooring systemthis fatigue mechanism be considered in addition to wheel fairlead tension bending, asapplicable. Note that the two effects will coexist, their relative importance governed bythe relationship between line working tension and dynamic tension range.

Figure 15-20 - Tension Bending at Wheel Fairlead (Bearing Load Eccentricity) andTension Bending from Interlink Friction (Torque at Contact)

The calculation of fatigue damage due to interlink friction at requires consideration ofthe chainhawse geometry and the friction coefficient. Having developed a relationship between link bending stress and motions of the unit, taking account of limiting valuesdue to the chainhawse geometry and slip between links, a conventional fatigue analysiscan 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 thatfor tension fatigue, a modified chain fatigue curve is thought to be appropriate.

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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 Gradientm

InterceptA

Notes

BOMEL JIP 3.173 11.46For use with single link in catenary

Adjusted for in water use

BOMEL JIP 3.173 11.02For use with 4000 link catenary.

Adjusted for in water useDNV 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 factoron fatigue life. This factor is typically dependent on the inspection regime and mayalso be affected by the criticality of the adjacent mooring lines.

The BOMEL JIP contrasts mooring chain failure, where loss of any one of manysimilarly loaded components results in total loss of the system, to failure within asystem where a degree of redundancy is present (e.g. a jacket). In order to account forthe increased probability that one out of the large number of links in the mooring chainwill fail a slightly more onerous curve is developed. Where a specific link (such as alink in the wheel fairlead) is considered, the single link SN curve parameters would beappropriate.

Traces of the three catenary fatigue SN curves, BOMEL catenary (BMLn), DNV

studlink OSE301 (DNVs) and API RP2SK (APIc) are illustrated inFigure 15-21.

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Figure 15-21 - Comparison between Various Mooring Chain S-N Curves

Factors on stress or fatigue life proposed in the various guidance notes may berepresented by factoring stress or life values, or alternatively by adjusting the interceptvalues 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 madeextremely difficult by location and poor access.

It should be noted that a visual inspection may not be sufficient to identify fatiguecracking in the chain links. Even under laboratory conditions [Ref. 10] quite largecracks could not be readily identified without the use of dye penetrant or somealternative NDE technique.

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15.5 Recommendations

The constraint offered to a chain link in a wheel fairlead is such that severance of onelimb of a chain link can occur without release of the mooring line. On this basis itcould be argued that repositioning of fairlead chain links into the mooring catenary beavoided 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 isavailable. 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 forthis.

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 toidentify rates of fatigue damage associated with bending-tension at the fairlead.

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16

FRACTURE MECHANICS AND CRITICALCRACK 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 thelikelihood of cracks leading to complete failure.

The basis of Fracture Mechanics is that it provides quantitative answers to structuralintegrity questions, such as the following:

x What is the critical crack size at service loads?

x How safe is the system if it contains a crack?

x How long might it take for a crack to grow from initial to critical size?

x How often should a particular structure be non-destructively inspected?

Fracture Mechanics provides a quantitative relationship, between material, design andfabrication, or more simply between stress , flaw size and toughness . Fracturemechanics is not only a powerful tool for analytical evaluation of Non DestructiveTesting (NDT) flaw indications, but is also helpful for the initial design, materialsselection 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 veryuseful 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 thefollowing:

1. The size and shape of the flaw,

2. The loading conditions/stress levels in the region of the flaw (Finite ElementAnalysis or Direct Measurement)

3. The operating environment, e.g. sea-water, splash zone, etc.

4. The fatigue/fracture mechanics properties of the material.

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There are real practical difficulties in obtaining, particularly in situ, the above data formooring lines (see Section 18). If it is not possible to detect and assess crack sizesaccurately the remaining life of the component under consideration will be highlyuncertain. For mooring components there can be very large variations in applied loadsdepending on the severity of any storms and the steepness of any waves which areexperienced.

Although it is difficult at present to detect cracks in situ, inspection technology willcontinue to improve. Thus it is important to continue to develop our FractureMechanics understanding with relation to mooring components. Although good workhas been done in this area – see below, it is clear that more work is still required. Forexample, it is important to identify the maximum defect size that can be permittedduring 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 toanalyze fatigue induced crack growth of mooring chains in dry air and in hostileenvironments. These include Vicinay Cadenas, Labein, Agder College of Engineering,Grimstad, and the Department of Metallurgical Engineering and Materials Science ofthe Bilbao Engineering Faculty (UPV-EHU).

To reveal fatigue crack behaviour in mooring chains, measurements were carried outfor high strength steel (Grade R4) in the Labein Laboratory, Spain, using CompactTension (CT) specimens with 12.7 mm thickness. These tests were performed in 1999and 2000 in accordance with standard ASTM E 647 procedures. The specimens weretested in air and in sea water with a frequency of 1 Hz. The fatigue crack growth wasmonitored by an Alternating Current Potential Drop (ACPD) method and the crackgrowth 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 atAgder University College, Norway. In this case Compact Tension (CT) specimenswith 25 mm thickness were tested in various environments under constant amplitudeloading. The fatigue crack growth was monitored by an Alternating Current PotentialDrop (ACPD) method and the crack growth rates were plotted as a function of theStress Intensity Factor Range (SIFR). The tests were carried out in dry air, in sea-waterwithout protection against corrosion and in sea-water with cathodic protection. Thecathodic potential was set to 890 mV and 1100 mV relative to an Ag/AgCl referencecell.

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The measured growth rates were compared with the rates for medium strength carbonmanganese steels as found in standard codes e.g. BS7910. The measured growth rateswere well within the scatter band given for these steels freely corroding in air. Thecrack growth rates found in seawater with cathodic protection were, however,substantially lower than the rates given in BS7910. When a cathodic potential of -1100mV was applied, crack closure was observed at medium levels of ' K . The explanationis the formation of calcareous deposit in the wake of the crack front that givessignificantly reduced growth rates and finally leads to crack closure. This finding is asurprise for high strength steel. The results are promising and should be investigatedfurther including the implications for the offshore operation of cathodic protectionsystems.

A linear elastic fracture mechanics model was established to study the fatigue behaviour in a studless link. The recorded growth parameters were used in conjunctionwith a crack-like initial flaw with depth in the range from 0.12 to 0.25 mm. Thedifference found between the growth rates in dry air and in free corrosion were inaccordance with tested fatigue lives for these two environments.

In general, after chains have been broken during fatigue testing microscopicobservations have been undertaken of the fatigue fracture surfaces to confirm the crackgrowth process and any initial defect. In this way it has been possible to adjust thevalidity 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 forchain inspection. Additional research is need in this area to identify what are thecritical crack sizes. This will be an important input in helping to develop newtechnology capable of detecting these sizes of cracks before they propagate through thematerial thickness.

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17

LINE STATUS MONITORING AND FAILUREDETECTION

17.1 Instrumentation Status - Survey Results

Given the safety critical nature of mooring lines one might imagine that they would beheavily 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 theindicative statistics below. On type a) turrets, in which the chains are permanentlylocked 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 andinstrumentation failure, without direct intervention?

Another factor which makes it difficult to be 100% sure of the condition of a set ofmooring lines is that line breaks do occur along the sea-bed or in the thrash zone. Ifthis happens the line will drag through the mud until the friction exerted by the soilsurrounding 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 arerequired to drag large diameter chain through the sea-bed.

The following indicative statistics, based on data from the majority of North Sea basedFPSOs, give an indication that instrumentation is not as prevalent as might be expectedfor such a heavily regulated region:

x 50% of units cannot monitor line tensions in real time.

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

x 78% of units do not have line failure alarms.

x 67% of units do not have mooring line spares available.

x 50% of units cannot adjust line lengths.

If the level of instrumentation/alarms in the North Sea is patchy, it seems likely thatunits operating in less heavily regulated regions will have even less instrumentation.

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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 NorthSea FSU. The Sonar head is deployed through the centre of the chain table toapproximately 15-20 metres below the hull. The head is deployed every 2 weeks incalm 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)

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The illustrated system is fairly simple and is easy to repair if something does go wrongwith 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 systemdoes have two important limitations, namely:

1. If a line breaks in the mud (not unknown) it will still have sometension/catenary and thus the change in the screen appearance may not besufficient to indicate that a line has failed.

2. A line could fail and not be detected for 2 weeks, during which time asevere storm could develop.

Figure 17-3 - Sonar Display Screen Showing 12 Mooring Lines and 2 Risers Close tothe 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 yearsinto its field life. If, however, FPSs were equipped on installation with the type ofsimple inclinometer shown on Figure 17-4 it would be possible to determine, in calmweather if any of the mooring line angles have changed to a significant extent. Theinclinometers could be checked using a “Football” sized ROVs which can be deployeddirectly from the deck of the FPS itself. This removes the need for expensive ROVintervention vessels – see Section 0. These small ROVs can be stored on the FPS itselfor can be sent out by a helicopter as the need arises. Simple inclinometers overcomethe difficulties sometimes encountered with damage to power and signal distributioncables on more complex systems. Being able to do a “fly by” in good weather to readall 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.

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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)

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17.2.3 Instrumented Mooring Lines

Intrinsically the simplest way to finds out if a mooring line has failed is to include aload cell in the line, ideally close to the fairlead, where the tensions are normallyhighest. Such a system is illustrated in Figure 17-6. Figure 17-7 shows the very usefuldata 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 readilyaccessible, if the sensor in or the wiring/connections fail, you are in the difficultsituation of not knowing whether the line has failed or the sensor has failed. If yourecord all line tensions and a line fails you should see tension pulses on the adjacentlines. These should be detectable if the recording interval is frequent enough and theload 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 linefailed, but it took two weeks of data processing from the other lines to reveal thetension spike that confirmed it was a real failure rather than an instrumentation fault.

Power & datatransmission

cable

Figure 17-6 - Instrumented Load Pin – Shackle Link (courtesy of BMT/SMS)

The power and signal transmission cables are areas of particular weakness for systemsexposed to long term offshore loading conditions. They may not even survive theinstallation operation. To quote from one project,

“The load monitoring systems are not commissioned yet. The load cell cables didnot last the tow from the conversion yard as they all came off their cable traysrunning up the side shell and were damaged - site did not use the specifiednumber and size of cable ties. All cables still to be replaced.”

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This quote shows the low priority which is typically assigned to mooring lineinstrucmentation.

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 itis not clear how these could be tested in situ to confirm whether or not they are stillfunctioning. Moving the trumpet assemblies with the chains in situ is not feasiblewithout 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 ontothe deck, it is relatively easy to confirm that the mooring lines are still present bysimple visual observation. Again, however, there can be a difficulty if a mooring linefails in the mud. For lines which cannot be seen clearly from the FPSO deck regularchecks 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.

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17.2.4 FPS Offset Monitoring and Line Failure Detection

If a mooring line fails the resulting equilibrium position would change and theoreticallyit should be possible to detect this based on offset monitoring. However, apart from indeep water, if a mooring line fails in moderate weather conditions it is difficult todistinguish the change in offset from the normal offset changes due to wind, wave andcurrent effects. Perhaps surprisingly mooring lines do fail quite often in moderateconditions, sometimes following on from storm loading.

In addition, the direction from which the weather comes from may influence theeffectiveness of offset monitoring for line failure detection. For example if a line failsand the weather pushes the unit in the direction of the failed line, the offset from theequilibrium position will be small compared to the weather pushing the unit in theopposite direction to the failed line.

Satellite drift and possible gyro malfunction can affect the accuracy of offsetmonitoring. For example a system is installed on one North Sea unit and this hasindicated 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 satellitesavailable at a particular time. In another incident the FPSO’s gyro became unstable andthis resulted in high apparent offsets. However, as long as false alarms do not happenso 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 wasnoticed 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 surprisingwhat mariners can deduce from experience and relatively little data. For example, ifyou are used to the FPSO taking up a certain offset in moderate south westerlyconditions and this, plus the overall response of the vessel seems to change, would be agood trigger to deploy a micro-ROV to check out the condition of the lines – seeSection 17.2.2.

It should also be noted that offset monitoring is a potential input to other possible linefailure 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 acoustictransponders deployed through the turret, attached to the hull of the FPSO (see Figure17-8 and Figure 17-9), or installed on the seabed to provide an indication of thecatenary’s profile. The advantage of these compared to the simple dipping sonardescribed in Section 17.2.1 is that, in calm conditions, it is hoped that they should beable 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 testedin the near future in the North Sea.

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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 practiceto 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)

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Vessel/ Mooringmathematical

model

PredictedVessel

Position &heading

Differencebetween

predicted &actual

Vessel responseto environment

MeasuredPosition &Heading

Revisemathematical

modelcoefficients

PredictedTidal Current

& direction

Draft Sensor

MeasuredWind Direction& Magnitude


model

PredictedVessel

Position &heading

Differencebetween

predicted &actual



Revisemathematical

modelcoefficients


& direction

Draft Sensor


17.3.1 Response Learning System (RLS) for Automatic Line Failure Detection

Another line failure detection option may be a Response Learning System (RLS) whichtakes into account the expected performance in measured weather conditions. Theresponse will be different if a line fails due to a resulting change in the mooring systemstiffness. If a unit is equipped with an environmental detection and recording systemand 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 whichillustrates this process. Hence, if the excursions do not match the predictions then anautomatic 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 developfurther. However, it has the real benefit that it would be a relatively simple retrofit toexisting installations, avoiding the need for expensive intervention work such asinstalling load cells and wiring. Also if the system breaks down it should be possible tofix it without any “wet” intervention.


model

PredictedVessel

Position &heading

Differencebetween

predicted &actual



Revisemathematical

modelcoefficients


& direction

Draft Sensor


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, whatis really wanted from a mooring perspective is real time mooring line tensions. This ismore complicated, but is believed to be achievable.

It is suggested that the following approach could be utilized to evaluate real time linetensions. The advantage of this approach, relative to strain gauges, is that no majorintervention 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 fairleadscan be determined and recorded.

3) Input the motion time trace into a high quality line dynamics mooringanalyses programme to evaluate line tensions.

Although the previous approach will give an estimate of the line tensions the accuracywill 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 thefairlead, say 30m.

2) Collect motions data for this point on the mooring line while also recording atthe mooring line while also recording at the same time data on fairleadmotion.

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 themaximum tension in a mooring throughout its length. This is because, depending ondynamic 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. Thesignal from the sensor can be acoustically transmitted to a data logger on the platformwithout the need for wires. On risers the sensors have been changed out by a ROVwhen 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 whichalways exists as to whether real behaviour is close to the initial predictions. This hasthe following benefits:

x A check can be made on storm loadings.

x Fatigue life predictions can be updated.

x 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 andtransmit 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 detectionis that Operators should have in place suitable performance standards for the time takento detect a mooring line failure. This is particularly important as common mode failuremechanisms, such as fatigue or wear, are likely to be prevalent on more than onemooring line and early detection of a line failure with appropriate mitigation strategiescould prevent system failure. Depending on the inherent redundancy of the mooringspread, the time taken to detect a failure could range from virtually instantaneousdetection to detection in a matter of days. It is clearly not appropriate to rely on annualROV inspection to check if a mooring line has failed. Monitoring the excursion of aFPS, 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 isunlikely 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 ofoffset 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 andanchors 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 insheltered water. Alternatively a spare line may be bought or rented, which can beswapped out with one of the existing lines while the original line is taken to the shorefor inspection and possible refurbishment.

FPSs spend much longer on location than MODUs. Hence, their mooring lines arenormally only recovered when the FPS moves off location. It is possible to recovermooring lines part way through a field life, but this has two disadvantages, namely:

1. The lines may be damaged either during recovery or re-installation2. 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 anddefects which may be present, there is an understandable interest among Operators toundertake in-water inspection. However, there will still be times when anomalies areidentified which can only be resolved with true confidence by undertaking in-airinspection. One definite advantage of in water inspection is that it is easy to identifywhich parts of the chain have been in the thrash zone and at the fairlead. This is moredifficult 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 highestdegradation and should be most closely inspected. In particular, in field experiencesuggests that the less loaded Leeside lines (see Figure 1-1 and Figure 3-4), which seemore 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 quitelocalised. Hence it is important to ensure that the ROV measures the right links on thesea-bed section. On Figure 7-9 the blue dotted vertical line shows the location of theno applied load touch down point. It is interesting to see that the blue line isapproximately 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.

OrcaFlex at 08:30 on 05/04/02:Block5_Multiple_Statics_Adj

50 mXY

Zmusted_Load_4_5_6_Uni_Sets_Steep_Sea_MPM_Excur_Laden.dat(az imuth=280;elevation=5) Statics Co

XY

Z

Figure 18-1 - Red Arrows and Black Line Indicate Key Areas subject to Degradationon 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 discontinuityas you change from wire to chain. Where there is a weight per metre discontinuity onemay experience increased relative rotation and thus wear. This seems to be particularly

pronounced on leeside lines.

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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 isgoing to be exposed to 20 years of dynamic motion, does it make sense to place itsomewhere 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 wasrecovered back to shore after six years of deployment in the North Sea. At the turretinterface 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 readyaccess to the chain stoppers than others. However, even for the type of turret illustratedin Figure 18-3 and Figure 18-4, the room at the base of the structure is flooded. Thusfor 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 MooringComponents are Submerged

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Figure 18-4 - Chain Stopper View Prior to Chain Installation with Pull in RiggingPresent (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 todevelop in-water inspection methods. This is because they are typically used in thesections of moorings subject to the greatest deteriorative forces, particularly at theseabed touchdown (thrash zone) and at the vessel interface. Both windward andleeward lines should be inspected, but a particular check for wear should be undertakenon the leeward lines, see Figure 3-4. Care is needed when inspecting the touchdownzone, since potential hazards such as rocks or debris on the sea-bed can cause mooringline abrasion. These hazards may be partially obscured by the sea bed/mooring lineand 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 withvarying success, ranging from simple diver-deployed manual callipers to a prototypestand-alone robotic system and ROV deployed systems.

Diver inspections are, in general, not a favoured option. Mooring chains are highlydynamic and therefore are potentially dangerous when divers are in close proximity.Also diver inspection has been proven to generate inconsistent results and has inherentdepth limitations, for example, when checking the thrash zone.

A stand-alone robotic system has been developed, but to date this seems to have beentoo large and cumbersome for practical offshore operations. In addition, it does notappear 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 duringdeployment onto chain they have the potential to be knocked out of ‘true’ andconsequently 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 highresolution 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 toolscale bars and resolving dimensions and optical distortions using offline image analysissoftware.

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 difficultto access regions such as the vessel interface. It can also be configured to measureother types of mooring ‘jewellery’ such as connectors, shackles and kenter links.

The ‘optical calliper’ chain measurement technology is used extensively by offshoreoperators and is accepted by a number of offshore certification authorities. In thisrespect, 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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block

guide

Camera

Underwaterlight

Deployment

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 incrack propagation and fatigue. Accordingly studded chain inspection and re-certification protocols require the assessment of the numbers of loose studs and degreeof ‘looseness.’ However, there is no consensual industry opinion with respect to loosestud reject criteria. Traditionally chains have had to be recovered for detailed loosestud determinations and have relied on a manual test, either moving the stud by hand orusing a hammer to hit the studs. The resulting resonance (a ‘ping’ or ‘thud’) is used toassess 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 thestud and uses a hydrophone and a micro-accelerometer as sensors. A software programis used to distinguish between ‘loose’ and ‘tight’ responses. Cross checks can becarried out in that very loose studs can be detected using a ROV manipulator or a ROVdeployed high pressure water jet.

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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 periodsaccumulate varying levels of marine growth which can be heavy, depending ongeography, water depth and season (see Figure 18-6). This growth needs to beremoved 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 orsynthetic 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 inspectionincluding general visual inspection (GUI), dimensional measurement and assessment ofmechanical fitness. Unfortunately cleaning off marine growth and scaling by high

pressure water jetting may accelerate corrosion by exposing fresh steel to the corrosiveeffects of salt water. At present there are currently no in-water inspection methods formooring components that do not require the prior removal of marine growth. Thisrepresents a technology gap, which warrants further investigation.

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The time required to remove marine growth depends largely on the cleaning optionchosen and in light of the cost of ROV vessels, can be a substantial component of thecost of an inspection program. Consequently it is essential that the planning stage ofmooring inspection campaigns should consider the most suitable cleaning options forthe 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 whatthe dimensions were of a mooring component when manufactured. Thus, thesignificance of any changes in component dimensions over time can be assessedcorrectly. With forged components, such as chains and shackles, there will tend to bean inevitable variation in dimensions. Section 3.2.7 provides indicative chainmanufacturing tolerances. Therefore, for key areas, such as at the turret interface, it isimportant 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 bemade of the condition of the wildcat pockets. The chain must be pulled in or let out toexpose the wildcat pockets which are hidden at a given chain position / fairleadorientation. 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 pocketson the gypsy wheel. These should be clear of marine growth and thus fairly easy toidentify once the line is slackened off. If this is not the case it would be good to markone of the links before the line is slackened off. If this is difficult to achieve the lineshould be slackened off a precise number of links so that one knows which links wereon the gypsy wheel. Taking some still photographs before the chain is slackened off isa wise precaution. It is desirable to take sufficient measurements at the top of thecatenary such that one can compare the wear on links on and close to the gypsy wheelwith those further down the catenary.

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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 todevelop in this area [Ref. 61].

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Figure 18-11 shows damage to a submerged wildcat or fairlead lubrication line as notedduring an abseiller based inspection operation. Although not all wildcats requirelubrication, if a system is designed to have lubrication it can be seen that it is fairly easyfor, even steel, lines which go through the splash zone to become damaged. Thisillustrates the difficulty experienced running power and signal transmission linesthrough the splash zone – see Section 17.2.3. If the wildcats are designed forlubrication and are without it for an extended period the chances of seizure areinevitably increased – see Section 8.

Figure 18-11 - Example of a Parted Lubrication Line Feeding a Submerged Wildcat orGypsy 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 exampleFigure 15-6, Figure 15-7 and Figure 18-12) it will be subject to regular bendingstresses. 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 whichlink will be sitting in a chain stopper or wildcat. Therefore, it is desirable to check theflatness of all the links at the end of the chain which may be held/constrained. Figure15-8 illustrates a simple gauge which can be used to check whether links are flat.

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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:

x Phase 2 – construction of a prototype and completion of onshore trials.

x Phase 3 – offshore proving trials.

An in air based wire rope inspection unit which was tested on ther Buchan FPS wireropes 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 difficultiesinvolved in inspecting wire rope and the age of some of the wires presently in use, it isrecommended that consideration should be given to moving forward with Phases 2 and3 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 resultingfrom irreversible deformations in the material under test. Very small changes inconditions at any point in a material normally produce a large number of emissions. Intheory these emissions can thus be used to detect, locate and characterise defects. A

prototype acoustic emission system was developed at Cardiff University but never gotto the stage of being sold on a commercial basis. A more update review of acousticemissions can be found in HSE Research Report 328 (2005) [Ref. 63]. The systemrelied heavily upon instrument software and a very powerful post-processing andanalysis 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 impressedcurrent or sacrificial anode systems it is important to check whether the system isoperational. For example, on one FPSO the earthing cables to provide electricalcontinuity 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 referenceelectrode 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 bemade 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 calcareousdeposits in the wake of the crack front.

Lloyds Rules and Regulations for the Classification of a Floating Offshore Installationat a Fixed Location (May 1999, part 8, ch 2.1.3, section 1.2.4) states a more negativevalue 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 hydrogeninduced 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 isdiscussed in detail in section 8.1.

With a ROV in the field it is possible to check the absolute accuracy of the mooringline tensions. This can be done in two ways:

1. Measure the x, y and z co-ordinates of the mooring line touch down point. Thiswill 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 RequirementsAnnual Surveys would typically be carried out by Classification Societies on mobileoffshore drilling units (MODUs) comprising visual inspection of the accessible chainlinks on or adjacent to the windlass. Intermediate Surveys are then normally performedat the second or third surveys following on from a 5 year special survey. Theintermediate surveys would normally be undertaken at a rig move and would include100% visual inspection of all the chain, excluding that which remains in the chainlocker during normal operations.

Since FPS’s are not subject to rig moves, intermediate survey chain inspections aredifficult/costly. Hence FPSs which are classed tend to concentrate on the 5 yearly

special periodic surveys. However, the fact that annual and intermediate surveys arefelt necessary for drilling semis shows that there is a need for regular inspection.

Lloyds Rules and Regulations for the Classification of a Floating Offshore Installationat a Fixed Location, (May 1999) state the following:

“2.2.10 For positional mooring systems a rota of component parts of the mooringsystem is to be examined at each Annual Survey. A periodic inspection

programme is to be developed by the Owners/operators and submitted to LR’sHeadquarters for approval. Annual Surveys should be capable of determining asfar 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:

x Cable or chain in contact with fairleads, etc.

x Cable or chain in way of winches and chain stoppers

x Cable or chain in way of the splash zone.”

It is interesting that no mention is typically made of the initial requirements forcalibration of tension meters, nor how often they should be recalibrated once the unithas 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 AreasInspecting 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 beinteresting to see if this leads to increased abrasion over time.

A c c e s sd i f f ic u l t ie s

f o r i n w a t e ri n s p e c t i o nf o r ja c k e ta b r a s i o n

Figure 18-15 - Example of a Difficult Area to Inspect

Chain in the trumpets and at the stopper is obviously difficult to inspect as previouslydiscussed – 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 bedifficult 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 notseem desirable !

However, if one pile or padeye degenerates and fails the rest will probably be in asimilar condition. Thus the danger of the system unzipping with multiple line failurescannot 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 longerknown 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 isstill fit for purpose.

However, if you no longer know what the break load is likely to be this makes testingsomewhat more problematic. The following outlines a method that has been usedsuccessfully at a chain test bed facility. It is worth noting that break testing can becheaper 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 expectedyield 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 theyield/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, andthat 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 startsto fall away.

It is worth noting that it is easier to set the load on some test machines as the tensionincreases, 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 theload) - is normal, rather than a clean break. The chain extension can be automaticallylogged into a data file monitored using infrared deflection monitoring equipment – seethe 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 goodopportunity to test worn mooring components.

There is also possible cross fertilization with flexible riser and particularly steelcatenary riser experience including touchdown zones and inspection techniques. Forexample:

1. Sea bed troughs at riser touch down zones

2. Dynamic behaviour including snatch loading and compression which may bedetectable by installed instrumentation

Listening for the Sound of Cracks

Ref. 20 states “Sounding the chain with a heavy hammer will reveal cracked orinternally corroded links or fittings. A sound link returns a clear, ringing tone; a badlink 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 issuggested that further investigation of this topic should be undertaken.

Figure 18-17 - Example of the Wheel Tappers Approach Used for Detecting Cracks onRailway 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. Thisinvolved changing out the worn chain at the trumpet with larger diameter chain with aspecially applied hardened coating (cobalt chromium) to reduce the severity of anyfuture wear. A special connector (see Figure 14-10) was developed to allow the newchain to be connected up to standard common link chain. This approach avoideddisturbing the wire section of the mooring line on the sea-bed, which is relativelysusceptible to damage (birdcaging). The original system designer was included in thereview process for the repair operation. This represents good practice which, where

possible, it is recommended should be followed for any future FPS mooring repairoperations.

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 strandwire since this can be relatively easily damaged – see Figure 6-5. Hence option 2 wasselected.

Figure 18-18 and Figure 18-19 give an idea of the complexity and hence the cost ofsuch a repair operation including anchor handling plus heading control tugs, DiveSupport Vessel (DSV), divers and winch operations on the FPSO.

Figure 18-18 - Example of Anchor Handling and Heading Control Tugs during aMooring 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 FPSOMooring Line Repair (coutesy of I. Williams)

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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 rentalcompanies. This may require the temporary use of second hand components such aschain. 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 shouldgive time for the procurement of the correct equipment, which may take around sixmonths depending on industry demand. Because the mooring system has beendamaged and then modified, it may be necessary to obtain concessions from therelevant Classification Society/Independent Competent Person (ICP). A reducedoperating envelope may have to be accepted during the period that the temporaryrepairs 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 withthe initial order so they are available during construction, pre-

commissioning and commissioning. Sort out the mechanism for budgetallocation early so it does not impact spares purchasing. Consider spareinstrumentation/transmitters; since these are long lead and critical forcommissioning.”

19.1.1 Operators’ Spares Club Not surprisingly no two FPS mooring systems are identical, since they are in differentwater depths and exposed to different environmental conditions. However, certaincomponents can be common between different units, for example, use of 120mmstudless 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 beavailable on a “first come, first served basis.” The established Marine Equipmentrental 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 RepairsFor a long field life the need to undertake mooring line repair is fairly high, even forrelatively benign climates, which will still suffer from wear and corrosion. Thus, it isimportant that FPS facilities should be designed from the outset, such that mooring linechange out is relatively straight forward. However, this is not always the case whichmay prove problematic in the long run. For example some Gulf of Mexico Spars haveutilised a temporary mooring line pull in winch deck, which is removed prior to settingthe 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 COMPREHENSIVEMOORING 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, itcan 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 froma 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 thedesign specification should consider and make reference to operations and long termintegrity.

To assist with long-term reliability it is necessary to be able to undertake inspection to alevel which gives real confidence in the condition of the as-installed system. Thisensures that intervention can be carried out early on, before detected anomalies getworse and place the system at risk. Mooring line inspection should ideally beundertaken in the water, since recovering lines is extremely expensive and may causedamage such as wires birdcaging. However, mooring design briefs typically pay littleattention 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 longhawse pipes or trumpets.

If the mooring design specification insists that key components of the mooring systemshould be readily accessible for inspection, this will force designers to pay moreattention to this long term integrity/reliability issue. In addition, the specificationshould state that the FPS design should allow for straight forward replacement in thefield of mooring lines, preferably using anchor handlers rather than specialist andexpensive construction vessels.

Mooring line instrumentation is another area which typically receives little attention atthe design brief stage. However, good quality instrumentation can potentially improvemooring integrity to a significant extent. At the same time instrumentation can help todetect problems early on which, without early intervention, can prove extremelyexpensive to repair at a later date. This is particularly the case if the intervention workresults in deferred production.

The cost of instrumentation is relatively low if it is incorporated in the design from theoutset. However, it is vital that instrumentation needs to be reliable. Offshorerepresents an exacting environment and thus best quality should be specified at the

beginning. The following parameters should typically be specified:

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x Line tensions monitored and the data permanently recorded at a suitable samplinginterval

x 24 hours monitored over tension alarms

x FPS offsets and bearings monitored and permanently recorded

x 24 hours monitored lines intact alarms

x 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 meansthat 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 toharsher climates, particularly with regard to fatigue. Therefore, depending on thecriticality of the fatigue assessment, it may be appropriate to undertake sensitivitystudies 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 thecapabilities of the likely installation vessels and their past performance on previous

projects. It is appreciated that during the early design phase that the particularinstallation vessels may well have not been identified. Hence, a degree of conservatismshould be incorporated in the design process, such that the required installationtolerances do not prohibit otherwise capable and perhaps cheaper vessels. This meansthat the mooring design brief should include suitable loadcases to account for lines atnon 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 andwhether 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, pretensionaccuracy, anchor placement accuracy, avoidance of chain twists, etc. Therefore, it isrecommended that a suitably experienced member of the mooring design team shouldgo offshore during the mooring installation and FPS hook up operation. This person isthus ideally placed to answer operational questions as they arise. Again this should bespecified in the mooring design specification so that contractors expect this and workwith 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 analysedduring the design process, it is important that key load cases should be re-run to ensurethat the system is still fit for purpose. Having sent a mooring designer offshore duringthe installation helps to ensure that whatever is analysed back in the office correspondsto the as installed configuration. In addition, feedback from the field helps to ensurethat the design of systems is continually improving and that sub optimum solutions arenot repeated. Again specifying a post installation check of the system performanceusing 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), nomeasurements 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 section18.5.

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 littlefurther involvement after installation. It is only if serious problems occur that thedesigners 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 operationto an Oil Company.

However, mooring systems are not as simple as they first appear and they need carefulmanagement through out their design lives. Thus a life cycle approach to mooringdesign and operation is recommended. In this way designers can feedback theirinspection requirements to Operators and then learn from whatever is found duringinspection. Hence, over time, mooring design should improve. At present designersare not always involved with the in field behaviour mooring systems. Hence they maynot be aware of operational or inspection type issues. Thus new projects may repeatdesigns from the past, which in some instances have certain limitations. Obviously ifsomething has been demonstrated to work well over a long deployment this is a goodargument for not changing it.

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21

KEY CONCLUSIONS & FUTURE WORKRECOMMENDATIONS

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 systemsfor floating production systems. A broad survey has been conducted of units aroundthe 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. Theresulting 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 anumber of cases where the integrity of the moorings has been compromised to someextent by unforeseen reasons. In part this is to be expected in any innovativetechnology, but there also appear to be some critical omissions in design and integritymanagement strategies. Significantly, during the course of this project failures havecontinued to occur. Clearly there is still much to learn on this subject and key areasrequiring further work are identified later on in this section.

Overall, based on the evidence acquired during the course of this JIP, as systems age, itseems quite probable there will be mooring failures in the future, unless more proactiveinspection 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 pointresulting 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 ofsuitable spares, such failures would be expensive to repair and might attract publicitywhich 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 meritgiven 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 failurecould put lives at risk both on the drifting unit and on surrounding installations. Thereis 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 theydeserve, particularly during inspection operations. One of the aims of this report is toeducate both offshore and onshore operational staff.

The interface between the surface vessel and the mooring line requires particularattention for all types of FPS. Carefully planned innovative inspection, making use ofall possible tools, has been demonstrated to be able to detect problems relatively earlyon before they become a potential source of failure. The use of micro-ROVs to gainaccess to restricted areas not accessible by conventional ROVs and divers has been partof the key to this success. The inspection which has been undertaken has shown theimportance of achieving compatible surface hardness, since it affects wear.Unfortunately, at present chain hardness and wear do not normally seem to beconsidered 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-griparea and to improve the marine growth cleaning off speed. At present no in-watertechniques exist to check for possible fatigue cracks and the development of suchtechnology should be encouraged which could include acoustic means – see section 0.Inspection access needs to be improved and this should be stipulated in the mooringdesign brief or specification.

On two North Sea FPSs chain wear and corrosion has been found to be significantlyhigher than what is specified by most mooring design codes. This wear seems to bemore pronounced on less heavily loaded leeward lines compared to the more loadedwindward 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 whichcould 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 longterm deployed mooring components will be reduced by wear, corrosion including

pitting and the possible development of small fatigue cracks. Thus to assess long-termintegrity with any confidence it is recommended that break tests on a statisticallyrepresentative sample number of worn components should be undertaken. Recoveredlines from the thrash zone and from the fairleads/chain stopper area would be ideal fortesting. Such material is likely to be available whenever a FPS comes off station or hasrepairs done to its moorings. As well as break tests, Magnetic Particle Inspection(MPI), photographs and comprehensive dimensional measurements should beundertaken. 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 asstandard on all units. In addition, all units should have readily available on board themaximum sea state in which they can continue to produce in case one line fails. Thisassessment should be based on intact system mooring line safety factors. On boardemergency procedures should identify what action should be taken in case of riserrupture while the risers are still pressurized, although the likelihood of this happening islow. During design the susceptibility of risers to be swept under moorings should beassessed, since if a line fell on a pressurised riser the consequences are likely to beserious.

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 designlife, but at this stage the moorings may no longer be fit for purpose. Hence, for longfield 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 findingstaking 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 longterm deployed units, it would be desirable to undertake an up to date wear assessmentto see how the calculated values tie up. Once a validated methodology has beendeveloped 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 drillingsemi-submersibles has been identified. This is believed to be due to rigs thinking theyhave set up balanced pre-tensions, when in fact this has not been achieved. Hence, it isrecommended that in field Pay-In/Pay-Out tests should be undertaken to check whetherthe 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 beennoted. 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 inthe short term with one or more failed lines. The reported statistics show that linefailures have been higher than might normally be expected for custom designedsystems which are not regularly recovered and redeployed. Thus the businessinterruption potential due to mooring problems should not be underestimated.

In general there seems to be a need for periodic Mooring Audits to re-assess originaldesign parameters and review inspection records to assess whether the system is still fitfor purpose. When considering possible mooring line remedial works and when itshould be done it is logical to look at the anticipated future life of the chains based onwear/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 largeraudience. However, it has also identified a number of areas which warrant furtherinvestigation to improve safety and reduce life cycle cost. The following list identifiesthe 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 theimplications for units which cannot adjust line lengths.

2. Calibrate an up to date wear/corrosion analysis model with long-term offshoredata (see section 7.6.2).

3. Engineering guidance for relative surface hardness for components expectedto be subject to long-term wear.

4. Assess how increases in proof stress may help the fatigue endurance ofmooring components – see Section 14.5.

5. Development of improved in water inspection techniques for hard to accessareas with the goal of being able to detect cracks.

6. The potential for cost effective micro/mini ROV mooring line inspection fromthe FPS itself.

7. Determining how chain strength is reduced by wear/corrosion is infancy andmore research and physical break testing of used lines and connectors isrequired. This work should also consider the applied ramp rate during breaktesting

8. Based on in field data, assess how removal of marine growth for inspectionaffects corrosion rates.

9. Possible methods to check the integrity of connectors in the water, includingnew 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 mooringintegrity and to review existing instrumentation and procedures.

12. The dynamics leading to relative axial movement and wear between chainlinks near the chainhawse needs to be understood so that it can be takenaccount 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 anaccurate wear/corrosion rate at the design stage.

13. Report on the in field performance of new mooring line instrumentation andfailure detection systems. Assess the feasibility of a Response LearningSystem (see Section 17.3.1).

14. ROV collection of soil samples from the proximity of mooring lines to assessthe concentration of sulphate reducing bacteria (SRBs).

15.

It is believed that there could be beneficial cross fertilization with flexibleriser and particularly steel catenary riser experience including touchdownzones 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 linefailure 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 toassist with the following:

x to evaluate fatigue in connectors, terminations, etc,x to evaluate bending and tension-bending fatigue in chains and also to

measure how chain surface finish can affect the friction between links,

x 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-Napproach, i.e. stresses by Finite Element analysis, strength derived from testson small scale specimen could be fruitfully used.

There are still uncertainties in estimating mooring loads using analysis software andmodel 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 workshould be done on this topic, although it is appreciated that there are difficultiesassociated with obtaining reliable weather and instrumentation readings. The effect ofmooring shock loading when subject to breaking waves should also be assessed – seeSection 3.1.10.

Overall there is a continuing need to monitor and report back to the mooringcommunity on issues which arise in future years as systems age, e.g. wear at FPSOtrumpets. This has been a particularly useful aspect of the Steering Committeemeetings to date and it would be desirable for this dialogue to continue. It is hopedthat this will be achieved through a Phase 2 Mooring Integrity JIP.

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22 REFERENCES AND BIBLIOGRAPHYRef. 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: aGuide 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 SciencePublishers B.V. , Amsterdam, 1992.

Ref. 4 International Organization for Standardization Draft InternationalStandard ISO/DIS 19901-7 Petroleum and natural gas industries – Specificrequirements for offshore structures – Part 7: stationkeeping systems forfloating 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 MaritimeDirectorate (NMD) and the Norwegian Petroleum Directorate (NPD)POSMOOR 1996.

Ref. 7 “Experimental Study of Load on an FPSO in Design EnvironmentalConditions” 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 “CorrosionFatigue Testing of 76 mm Grade R3 & R4 Studless Mooring Chain dated15 May 2002 (Report No: H5787/NDAI/MJW Rev 0).

Ref. 9 “New Mooring Chain Designs” by Luis Cañada, Javier Vicinay, AlejandroSanz, Eduardo López Vicinay Cadenas, SA., OTC 8149, 1996.

Ref. 10 Billington Osborne-Moss Engineering Limited (BOMEL) “DesignGuidelines for Anchor Chains” – Final Report (Report No: C538R002.04Rev 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 May1994, pp. 171-191.

Ref. 12 “Assessment of Mooring Chain from Mobile Drilling Unit,” 19 th 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” byMing-Yoa Lee, American Bureau of Shipping, Paul Devlin, Texaco Incand Chi-Tat Thomas Kwan, Consultant.

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Ref. 15 Guidance Notes on the Application of Synthetic Ropes for OffshoreMooring 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 – AnIntroduction to their Properties and Applications”, Pergamon Pess Ltd.,1980.

Ref. 18 DNV Certification of Offshore Mooring Chain, Note 2.6 dated August1995.

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 Stormsof October 1991 and January 1992 Issued January 1992.

Ref. 22 Offshore Technology Conference 2004 Paper “Post Mortem FailureAssessment of MODUs during Hurricane Lili” BP Malcolm Sharples,Offshore Risk & Technology Consulting, Charles E Smith, MineralsManagement Service and Robert G Bea, University of California atBerkeley.

Ref. 23 Offshore Technology Report 2000/086 – Operational Safety of FPSOs:Initial Summary Report prepared by Norwegian University of Science andTechnology (NTNU) for Health and Safety Executive.

Ref. 24 Jatar, S., Haslum, H., and Tule, J., “The Design, Testing and Installationof the Red Hawk Spar Polyester Taut Leg (TLM) System, 16 th AnnualDeep Offshore Technology (DOT), New Orleans, Nov. 30 th – Dec. 2 nd.

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., 16 th Annual Deep Offshore Technology (DOT),

New Orleans, Nov. 30 th – Dec. 2 nd.

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 ofPractice for General Criteria.

Ref. 29 DNV Rules for Classification of Mobile Offshore Units – SpecialEquipment and Systems Additional Class, Part 6 Chapter 2 July 1989Position Mooring (POSMOOR).

Ref. 30 API Recommended Practice 2I, ‘In-service Inspection of MooringHardware for Floating Drilling Units’, Second Edition, December 1996.

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Ref. 31 API Recommended Practice for Design and Analysis of StationkeepingSystems 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, 3 rd international OffshoreMoooring Seminar.

Ref. 33 “Mooring Chain Corrosion Design Considerations for an FPSO in tropicalWater” by Mark Wang and Richard D’Souza, Deepwater Technology atKellogg Brown – Proceedings of OMAE-FPSO I2004 OMAE SpecialtySymposium on FPSO Integrity, Houston USA 2004 - Paper No: 04-0046.

Ref. 34 Failure Analysis of a CALM Buoy Anchor Chain System by G. J. Shoupand 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 extendingthe useful Life of In-Service Anchor Chain,” OTC 5719, 1988.

Ref. 36 HSE Research Report 219 “Design and integrity management of mobileinstallation moorings” P.J. Donaldson, M. Brown and M. Pithie (NobleDenton).

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. HansTreu (SEA Engineering) Presented at Offshore Technology Conferenceheld in Houston 3-6 May 2004, OTC 16523.

Ref. 40 “Na Kika – Deepwater Mooring and Host Installation” A.K. Paton (ShellInternational E&P Inc.), J.D. Smith (Shell), J.A. Newlin (Shell), L.S.Wong (Shell), E.S. Piter (Edmar Engineering Inc); C. van Beek (HeeremaMarine Contractors BV). Presented at Offshore Technology Conferenceheld in Houston 3-6 May 2004, OTC 16702.

Ref. 41 Noble Denton Europe Limited Joint Industry Project “The Evaluation ofWire Mooring Line Strength and Endurance, Additional Testing of SteelWire Rope” – Final Report (Report No: L17294Rev1/NDE/RWPS) dated16 February 1996.

Ref. 42 Noble Denton Europe Limited Joint Industry Project “The Evaluation ofWire Mooring Line Strength and Endurance (Old Ropes II)” – FinalReport (Report No: L18085/NDE/RWPS) dated 2 April 1997.

Ref. 43 Reading Rope Research “The Inspection & Discard of Wire MooringLines” C. Richard Chaplin December 1992. Prepared as a supplement for

participants in a joint industry study on an Appraisal of DiscardedMooring Ropes.

Ref. 44 Final Report of a Joint Industry Study on Prediction of Wire RopeEndurance for Mooring Offshore Structures, working summary by CRichard Chaplin, Department of Engineering at university of Reading

August 1991.

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Ref. 45 Noble Denton Europe Limited Report for TotalFinaElf Exploration UKPlc “Investigation into the Run-out of Number 6 Mooring chain on“Transocean John Shaw” (Report No: A4071/01/NDE/CLC/Ls) dated 20February 2003.

Ref. 46 HSE Offshore Technology Report – OTO 98 086 “Quick Release Systemsfor Moorings” issued April 1998.

Ref. 47 HSE Offshore Technology Report 2001/073 “Failure modes, reliabilityand integrity of floating storage unit (FPSO, FSU) turret and swivelsystems”.

Ref. 48 “Turret Operations in the North Sea: Experience from Norne and AsgardA” 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 floatingmonohull and fixed installations’ prepared by Martin Muncer , ResearchReport 047, 2003

Ref. 50 Petroleum Safety Authority Norway “Trends in risk Levels – NorwegianContinental 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 forMooring Systems” 1997 NI 432 DTO R00 E 1997.

Ref. 54 OTC 6905, 1992, “The Influence of Proof Loading on the Fatigue Life ofAnchor 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 andIndustry, “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 CriticalReview of Wire Rope Endurance Research Affecting OffshoreApplications, HSE, OTH 91 341, 1991.

Ref. 60 “Cost Effective Mooring Integrity Inspection Methods,” Hall, A.D., OTC2005, May 2-5, Houston, paper 17498.

Ref. 61 Performance and Testing of Components of the Ivanhoe/Rob Roy FloatingProduction System Mooring, J.R. MacGregor and S.N. Smith, Amerada

Hess Ltd, and J.E Paton, JP Kenny (Caledonia), OTC 7492 1994.

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Ref. 62 Joint Industry Project - Sub Sea Electrol Magnetic Appraisal of WireMooring 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 anddamage” 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” APISpecification 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) UniversitéLyon, France. 1995.

Ref. 69 “Engineers Design Guide for Deepwater Fiber Moorings”, 1 st Edition, NDE/TTI Joint Industry Project, January 1999.

Ref. 70 OTC paper 10798, 1999 “Genesis Spar Hull and Mooring System : ProjectExecution”, (W.F. Krieger, Chevron Petroleum Technology Co., J.C.Heslop, Chevron U.S.A. Inc., B.E. Lundvall, Exxon UpstreamDevelopment Co. and D.T. McDonald, Chevron U.S.A.

Ref. 71 NACE International, The Corrosion Society “Corrosion Control of SteelFixed Offshore Structures Associated with Petroleum Producetion NACEStandard 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 “AReview of Available Laboratory Test Data on Mooring chainApplications” dated April 1998.

Ref. 74 Health & Safety Exeuctive Offshore Technology Report ITO 96 018“Improved Reliability of Mooring Chain Systems” dated May 1997.

276



A4163-01

23 APPENDIX A - SUMMARY OF PAST RELEVANT

JIPS

x Engineers Design Guide to the use of Deepwater Fibre Mooring Linesx 1996, 31 participants, RWPS most knowledgex Corrosion Fatigue of Studless Mooring Chainx 2002 final report, Noble Denton Houstonx Subsea Electro-Magnetic Appraisal of Mooring Lines (SEAL)x 1995 Noble Denton Londonx Evaluation of Wire Mooring Line Strength and Endurance

x 1996/97 Old Ropes 2 and 2.5x “Mooring Code Joint Industry Study” ,x Noble Denton & Associates, October 1995x Fatigue Tests for Large Diameter Mooring Anchor Chainsx 1994 Final report H3241/NDAI/JIS, Houston work,x High-Technology Fibres for Deep Water Tethers and Mooringsx 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

278



A4163-01

24 APPENDIX B – MOORING INTEGRITYQUESTIONNAIRE (EXCEL)

279



Nan-Hai-Sheng-Li-(CNOOC-SOFEC)-sketches.xls

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 directionsystem ?

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

B8. Length & make up of grounded length section

m

B9. Length & make up of catenary section

m

B10. Length & make up of final line section into FPS

m

B11. If applicable position, make up & length of any weighted line sections or buoyancy modules

JOINT INDUSTRY PROJECT: FPS MOORING INTEGRITY

QUESTIONNAIRE

310

Chain

AB S

No

No

?

?

? a

?

No

No

No

of

of

of

of

Nan-Hai-Sheng-Li Liuhua, South China Sea

Turret FPSO

South East Asia

Mar 1996

W ire R ope Polyester Rope

Catenary

Classification Soc iety:

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 W ire + s ubsea buoy + spiral str

4.5" Ramnas S tudded Chain

A dra w ing of the 25te ne t buoya ncy subse a buoysw ould be a ppre cia te d.

Yes

N.A.

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

?

20

No

Not Applicable

SOFEC

Free weathervaning

Don't know

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?

W ire Rope Drum -type

Chain Stopper

Submerged - Base of turret

Vertically

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?

?? mm

??? m

Other, please specify Anc hor S hack le

Other, please specify Socket - triplate - shackle

Other, please specify Shackle - triplate - socket. P lease adviseconnections to subsea 25te net buoyancybuoy?

Other, please specify Socket - triplate - shackle

Don't know

Combined Stopper & Trumpet Assembly

Vertically

Other, please advise Please advise ?

Yes How Much?

Yes How Deep?

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 k now

Don't know

???????

Please advise ?

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 installationH4. 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

??

No

No

Other, please advise The line tensions, in terms of chain angleat the trumpets, are only measured duringinitial installation and during inspectionsurveys ???

Yes

????

Don't know

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 specifyPlease advise ?

Classification Society Requirement

Yes

Other, please specify General visual inspection by ROV ?

Other, please specify

Have you used the W elaptega Marine ROV ca mera basedsystem for detecting wear? If not, have you used any vaguelysimilar system ?

Is visual inspection almost imposs ible due to the chain st oppersbeing at the end of a trumpet or hawse pipe surrounded by thespider structure ?

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 thetrumpets 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?

No

No

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 deployedprobe ?

Not Rec overed

Not Applicable

Not Applicable

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? n

Yes

Yes, please supply details ????

Yes

Instrumentation readouts + Experie

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

No

No

Connectors

W ire Rope

Chain

Fibre Rope

Instrumentation

Other, please specify Do you hold any spares ?

No, I want to create Line Failure IncidentReports

Questionnaire



1. Incident Description:

2. When did failure occurr?

3. Details of Failure:

JOINT INDUSTRY PROJECT: FPS MOORING INTE

INCIDENT REPORT EXAMPLE

Failure of the re taining bolts on a w ire open socket whichallowed 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 connectiondetail between the chain and the wire consisted of a wire endsocket, a triplate and a D type shackle connecting to thegrounded chain. The wire open socket was connected to thetriplate by a round connecting pin that wa s held in place by anend plate secured to the socket by 3 bolts aorund itscicumference ands to the pin by three bolts in a line. During asubsea survey it wa s found that the end pla te had droppe d offand the pin dropped out. It was also noted that the end platebolts had faile d or backed off on a number of the other socketconnections 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 thecatenary (the thrash zone) and as the wire socket was repeatedlypicked up and set down there w as a la rge relative motionbetween the socket and thge heavier triplate and grounded chainsection that typically remai ns on the sea-bed. It is thought thatthis introduced a large torsional/friction load between the pinanbd the body of the socket that could not be a ccommoda ted bythe end plate retaining bolts and these failed allowing the endplate to drop off and the pin to fall out. There ha d also been afailure to insulate properly the wire section from the chainsection and the cathodic protection on the wire weas draineddown by the grounded cha in section resaulting in a corrosiveenvironment that might have contributed to the failure.

Temporarily restricted offloading operations plus repair costs.

Subsea ROV survey



A4163-01

25 APPENDIX C – 2005 OTC JIP PAPER

280



OTC 17499

Floating Production Mooring Integrity JIP – Key FindingsMartin G. Brown, Noble Denton Europe LimitedTony D. Hall, Welaptega Marine LimitedDouglas G. Marr, Balmoral Marine LimitedMax English, U.K. Health and Safety ExecutiveRichard O. Snell, B.P. Exploration

Copyright 2005, Offshore Technology Conference

This paper was prepared for presentation at the 2005 Offshore Technology Conference held inHouston, TX, U.S.A., 2–5 May 2005.

This paper was selected for presentation by an OTC Program Committee following review ofinformation contained in a proposal submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Offshore Technology Conference and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Offshore Technology Conference, its officers, or members. Papers presented atOTC are subject to publication review by Sponsor Society Committees of the OffshoreTechnology Conference. Electronic reproduction, distribution, or storage of any part of thispaper for commercial purposes without the written consent of the Offshore TechnologyConference is prohibited. Permission to reproduce in print is restricted to a proposal of notmore than 300 words; illustrations may not be copied. The proposal must contain conspicuousacknowledgment 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 aJoint Industry Project (JIP) to investigate how to improve theintegrity of the moorings used by Floating Production Systems

(FPSs). The JIP has surveyed the world wide performance ofall types of FPS mooring systems including FPSOs, semisubmersible production units and Spars. Wide rangingsupport from 23 sponsoring organizations including operators,floating production contractors, regulatory authorities,equipment suppliers and inspection companies has enabledaccess 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 onstation for many years. Review of inspection data from theseunits shows that selective repair may be needed to maintainthe design specification right up to the end of the operationallife. It has been found that wear can be faster on leeside, asopposed to windward lines and that certain weighted chaindesigns are susceptible to damage.

The likelihood of line failure and the implications need to be better appreciated. Following failure, it may well take severalmonths to implement a full repair, due to a lack of

spares/procedures and possible non-availability of suitablevessels. However, it has been found that carefully plannedand coordinated inspection operations can detect potentialissues early on before more serious deterioration takes place.In general, mooring monitoring/instrumentation and access forin-water inspection seem not to be as advanced as might beexpected for a system which is safety critical. Hence good

practice recommendations are included which can be appliedto both existing and planned future units.

Introduction

Unlike trading ships, Floating Production Systems (FPS’s),

stay at fixed positions year after year without regular drydocking for inspection and repair. Since they cannot move offstation, they must withstand whatever weather is thrown atthem. Hence at times, depending on their location, theirmooring systems need to withstand high storm loadings.Typically during design, mooring systems for harshenvironments do not have much reserve capacity above whatis required to withstand survival conditions. Thereforedeterioration of the lines over time can increase the likelihoodof single or multiple line failures. Multiple line failure couldconceivably result in a FPS breaking away from the mooringsand freely drifting in the middle of an oil field.

The Mooring Integrity JIP has been concerned with assessinghow mooring systems have performed in the field to identifythe level of degradation which has taken place. Hence the

project has looked at FPSOs, Semi submersible productionunits and Spars through out the world. The key objectiveshave been:

• To feedback operational and inspection experience tothe industry and to mooring designers

• To publicize how hard moorings work, theirimportance and potential vulnerability

• To disseminate best practice guidance



2 [OTC 17499]

From the survey it has become apparent that certain problemshave occurred and thus the JIP wishes to publicise these sothat they can be taken account of during inspection of existingunits and during the design of future units. Taking dueaccount of past experience is particularly important when adesign premise or specification is being developed for a new

project.

International Survey

Significant effort was made to try and ensure that theinternational survey was as simple and straight forward as

possible for respondents. To this end a custom designedspreadsheet based questionnaire with drop down boxes wasdeveloped. 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 theindustry. Conference papers, in-house data and journals werealso consulted. Response to the questionnaire was reasonable,

but could have been better particularly for non North Searegions. This perhaps gives some indication of the prioritylevel that at present seems to be associated with mooringsystems. Initially it was believed that offshore based staffwould be able to complete the questionnaires. However, it

became apparent that in some assets there is little in-depthknowledge about the make up and history of their mooringsystems. Overall though, in summary, good data wasobtained, but not on as many units as had been originally

planned.

Degradation Mechanisms

Intrinsically mooring lines present a fairly simple system forkeeping a floating object on station. However, experiencefrom the field has shown that mooring is in fact a particularlydifficult dynamic problem. Figure 1 illustrates a number ofthe degradation mechanisms which a mooring system will beexposed to every day of its operational life. Inevitably the

performance of the system will decrease over time. Despitethis, at the end of the field life, which in certain circumstancescould be in excess of 20 years, the mooring system normallystill needs to be capable of withstanding 100 year return period

storm conditions. This represents a stern test for any 20 yearold mechanical system. It is also logical that the longer amooring system is out there, the higher is the probability that itwill encounter extreme weather conditions.

Many of the mooring issues mentioned in this paper refer tochain. This is because chain is normally selected at the twomost challenging locations, namely the vessel interface andthe sea-bed touch down. Since the loading regime is severedegradation may sometimes occur. However, experience overthe years has shown that using wire in these areas does notgive a true long term solution. The same would almostcertainly apply to the use of fibre ropes.

Corrosion

Wear & fatigue

Bending & Tension

Highest Tensions

Impact & Abrasion

Figure 1 –Mooring degradation and the key areas to inspect

Historical Incidents

Given these degradation mechanisms a search was made ofhistorical records to see what lessons could be learnt from pastincidents. This search identified the following incidents whichcould have implications for present day systems, although

particularly for the SALM the failure mechanism was uniqueto the system concerned:

• Argyll Transworld 58 production semi, complete break away in 1981

• Fulmar FSU, complete break away in 1988 from theSALM (Single Anchor Leg Mooring).

• A series of semi sub multiple line failures in thestorms of Oct. 1991 and January 1992, see ref 5.

• Petrojarl 1, 1994, 2 lines failed at the same time whenhit 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. Thesedurations tie in surprisingly well with the failure statisticsreported later on. The TW58 was designed to and haddisconnected its risers before breakaway, but it was still freedrifting for 1.5 days in the North Sea before it was possible toattach 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 muchdamage can be inflicted by unusually severe, but not freak,storms. The Petrojarl incident is significant since it shows thatif there is a common degradation mechanism multiple linefailure may occur virtually at the same time. In this caseredesign of the chain guides and up-rating the chain resolvedthe particular problem.

Consequences of Mooring Failure

Environmental ImpactThe design premise of the majority of FPSs is that they should

be able to withstand a single mooring line failure without theresulting increased vessel offset causing damage to the risers.Multiple line failure is only likely to occur if a failure has goneun-detected (see later) or if there is general degradation which



3[OTC 17499]

is affecting all lines in a particular quadrant to approximatelythe same extent, see Figure 2.

Figure 2 – Possible Line Failure and Repair Scenarios

In the unlikely event of multiple mooring line failure causingrupture of one or more risers, the extent of hydrocarbonrelease will be strongly dependant upon whether or not therisers are still pressurized. Typically it is assumed thatmooring line failure will be progressive and thus there will besufficient time to shut down production and depressurize therisers, before the resulting increased vessel offset causesdamage. However, the multiple mooring line failure whichoccurred on Petrojarl 1, when hit by a shock-inducing steepwave, shows that loss of position keeping on a non DP assistedvessel could occur remarkably quickly. This could possibly bein wave heights below survival criteria. Hence, it isrecommended that on-board emergency procedures shouldidentify what action should be taken in case of single ormultiple riser rupture while the risers are still pressurized.

If the risers are depressurized when rupture occurs, the extentof possible hydrocarbon release ranges from 100m 3 to2,500m 3. This depends on field specific architecture such asthe number of risers and the step out distance of the flowlines.

Business Interruption ImpactThe business interruption cost of a single mooring line failureis 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 followingcosts 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, butresults in shut down for an extended period, would cost muchmore than the figures outlined above.

Causes of System Degradation - Case StudiesCorrosion and Wear – North Sea Production SemiA fascinating insight into the possible future performance ofmodern 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 FPShas experienced three mooring failures, plus significantdefects have been found on two other lines during inspection.Interestingly all three line failures have been on lines whichare defined as leeside lines based on prevailing weatherconditions (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 firstthought it might be expected that greater wear would beexpected 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 samemovement of the surface platform.

Figure 3 – Illustration of Windward and Leeward Lines

On this unit the failures have typically been on chain which atthe no load equilibrium position is somewhat above the touchdown point. Hence, in-water inspection during calm weathershould 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 studdedchain has shed studs – see Figure 5. This is interesting, sinceit proves that studded chains can lose studs in situ rather than

just during the relatively harsh handling that chain receivesduring a recovery operation by an anchor handling tug.

Figure 4 shows a recovered link which was close to the linkwhich failed in service. The failed link could not be found onthe sea-bed. On the photograph it is interesting to note that thearea of maximum wear is not at the point of contact betweentwo links under tension, otherwise known as the inter griparea. Instead it is part way down the inner face of one side ofthe link. Damage was also noted on the crowns of other links.

This suggests that some form of dynamic impact/grindingaction is occurring which is wearing down the links.Significant inter link motion is thought to have been a factorcontributing to the shackle pin failure illustrated on Figure 9.

Losing material in this area is significant, since a finiteelements analysis of a link will confirm that this is a highlystressed area. This is one of the reasons why it isrecommended that tests should be undertaken to determine theactual break strength of worn mooring components.



5[OTC 17499]

trumpet section (see Figure 6 ). This was first experienced onan early S.E. Asian external turret moored FPSO and morerecently on an internal turret moored N. Sea FPSO. For theinternal turret a slight shadow was seen on one of the chainsduring 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 capabilityof using a football sized micro-ROV to get in close to the bellmouth could be evaluated. This concept proved to besuccessful as can be seen from the photograph taken by amicro-ROV in the field, see Figure 7.

Figure 6 - Test Tank Mock-Up of Micro-ROV inspection of ChainEmerging 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 rubbingagainst the weld beads with a replaceable material (ultra highmolecular weight polyethylene sheeting). However, for thesubmerged trumpets on the North Sea unit a more long-termrepair was needed which involved changing out the wornchain at the trumpet with larger diameter chain with aspecially applied hardened coating (cobalt chromium) toreduce the severity of any future wear. A special connector(see Figure 15) was developed to allow the new chain to beconnected up to standard common link chain. This approachavoided disturbing the wire section of the mooring line on thesea-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 practicewhich, where possible, it is recommended should be followedfor any future FPS mooring repair operations.

On type a) systems the trumpets are typically pivoted about asingle axis so as to minimize chain rotation and wear. Sincethe rotation is only about one axis and the trumpets arearranged around an approximate circle, the pivoting actioncannot eliminate chain rotation for all the lines at the sametime. Thus, to minimize wear over a long field life, there may

be arguments for selecting a design which can pivot about twoaxes, although this would be mechanically more complicated.

Figure 7 - Micro-ROV Photograph of Chain Wear Notches whereChain Emerges at the Trumpet Bell Mouth

Trumpets or guides are included on type a) FPSO designs tohelp guide the chain into the chain stopper. The trumpetsthemselves may include “angle iron” guides to ensure that thechain is in the right orientation when it enters the chainstopper. Once the chains are tensioned the trumpets have noreal purpose unless they are required in the future for a newchain pull in operation. Interestingly, the pivoting chainstopper design which was adopted for the Brent Spar buoy didnot include trumpets to help guide in the chain. The BrentSpar mooring was a successful design with a 19 yearoperational life and minimum wear on the chains at thestoppers when they were examined when the Spar was cut upin Norway. There was one failure but this was at a kenterconnecting link. Such a failure is not surprising, sincestandard kenters are known to have low fatigue lives. Thereare, fortunately, now new designs of kenters with improvedfatigue lives, but these still do not at present haveclassification 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 thatthe trumpet assembly does not automatically follow themotion of the chain. In fact it is contact between the chain andthe outer face of the bell mouth which causes the trumpet torotate. It is this contact, plus an associated sliding/sawingaction, which seems to have led to the chain notches shown onFigure 7.

Intrinsically there does not seem to be any reason why thechain stopper should be inboard of the pivot point. If it isoutboard of the pivot point movement of the chain shouldcause movement of the trumpet without the need for chaincontact 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 itwould appear that long trumpets are not helpful after thecompletion of the installation process. Thus it isrecommended that careful checks should be made on any unitswhich fit this category.



6 [OTC 17499]

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

Friction Induced BendingWhen a chain is under tension there will be friction and localyielding between the links which will inhibit inter linkrotation. It is found that the higher the tension in the line, thegreater 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 aswater depths and line pre-tensions increase. Over timecyclical out of plane loading can cause fatigue damage. Thishas been illustrated by a number of fatigue failures which haveoccurred 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 differentgeographical locations areas on relatively short assignments.Today, for long term moored units, a fatigue assessment istypically carried out (refs. 3, 4 and 6). Such an analysis isnormally in terms of tension loading cycles; it does notconsider the combined effects of bending and tension. Forlong term moored units it is clear that friction induced bendingfatigue should be evaluated. This is particularly important fordeep water taut moored systems, but will still have somerelevance for units in more moderate water depths. Physicaltesting 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 linkswhere they emerge from the bell mouth can significantlyaffect 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 thesea surface.

Excursion Limiting Weighted Chain and Mid Line BuoysFrom a mooring design perspective increasing the chainweight for a section of mooring line in the thrash zone can bea 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 beachieved. However, from the international survey it is clearthat great care is needed to select a robust system if such anapproach is adopted.

One way of increasing the chain weight, is to hang off shortchain lengths from the main mooring chain. This was thesolution adopted on one harsh environment FPSO. However,Figure 9 illustrates the damage that has been caused to one ofthe pins. It is believed that this damage may well have beencaused by a dynamic pinching/grinding action of adjacentlinks.

Figure 9 – Photograph of a Partial Failure of a Hang-Off ShacklePin

Another possible approach to increasing the line weight over acertain section is to attach clump weights to the chains.illustrates half of a clump weight from a FPSO mooring linewhich utilized such a system. In this instance it can be seenthat the bolts which kept the two half shells together havefailed and the clump weight has thus split open. Again thedynamic loading of the line is thought to have led to the failureof the restraining bolts.

Figure 10 - Chain Clump which has become detached – only onehalf of the Clump Weight Visible



7[OTC 17499]

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. Thisis because enhanced wear may be experienced due to anincreased rotation resulting from a change in the weight per

metre at the connectors.

An alternative way of reducing FPS excursions due to meanwind, current and wave drift forces is to add buoys on to themooring lines. However, problems have been experienced onone FPSO with the buoys becoming disconnected from thelines over time. Interestingly this seems to have been onleeward lines, which indicates that that the increased motion ofthe 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 11illustrates an unintended line disconnection on a FSU. Thissocket was at the transition from wire rope to chain. Hence,there was a weight per metre discontinuity which resulted inextra rotation at the connector. In this instance the socket pinwas restrained from rotating by relatively small bolts. The pinwanted to rotate and it eventually sheared the bolts on the endcap which allowed the whole pin to work loose. It isinteresting to note the size of the locking-pins which make upthe double locking system on the purpose designed connectorshown on Figure 15. The substantial size of these pins was

based on hand calculations utilizing the expected line loadsand an estimated friction factor. In the case of the unintended

disconnection, at times, depending on vessel offset, theconnectors would have been in the thrash zone. They wouldhave experienced repeated lift up/set down contact with thesea bed.

Figure 11 - Unintended Line Disconnection due to the Failure of aSocket Restraining Mechanism

“Dog Leg” or Wavy Mooring Lines on the Seabed

During mooring line installation it is important that all linesshould be laid straight from the anchor to the fairlead at the noload equilibrium position. This requirement should beemphasized 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, thiscan lead to unbalanced mooring line tensions. In other wordsa system which was balanced originally with the “dog legs”may no longer be so. If one line takes more of the loadcoming in from a particular quadrant it is more likely to fail.If this originally taut line fails, the FPS may exceed itsallowable 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-tensioningoperation and the storm loadings which have been experiencedhave been insufficient to overcome the friction of the lines inthe sea-bed mud. But to date, these FPSOs have not yet

experienced storm line loadings as severe as the maximumloadings evaluated during the mooring design process. It will be interesting to see if, over the respective field lives, the “doglegs”/wavy lines are pulled straight or not and this should bemonitored during annual ROV surveys. If straightening doesoccur the implications for mooring behaviour should be fullyevaluated.

Unbalanced Set-Up Pretensions

On a long-term moored semi-submersible FPS, offshore personnel doubted the tension readouts on their mooring linewinches, since damage was occurring to the wires on the

winch drums. In addition, when grappling for certaincomponents on the mooring line they were not found at theexpected depth.

Therefore, in calm weather, an underwater ROV survey wasundertaken of the triplate connectors to obtain their X, Y andZ co-ordinates. From these positions and knowing thesubmerged weight of the line, it was possible to perform acatenary calculation to estimate the actual line tension. Thesetensions can then be compared to the winch tension readouts.This process showed that in the worst instance the calculatedand the measured tensions were out by 160% !

Tension meters fitted to the base of pull in winches/windlassescan give a poor estimate of the tension in mooring lines, evenif properly calibrated, since the amount of friction in thesheaves/fairleads is variable and difficult to quantify. Inaddition there is a possibility of full or partial seizure of thesubmerged lower sheaves or wildcats. To check this out,during a period of good weather, a carefully controlled LinePay-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 thewinch tensions noted. If this test is undertaken relativelyquickly in calm weather conditions it would be expected thatthe same line tension would be obtained for the same line

payouts. In actual fact this did not prove to be the case for allmooring lines, see for example Figure 12.



8 [OTC 17499]

reported to the UK Health and Safety Executive (HSE).Although the North Sea is a hostile climate, units intended for

Line No11 use here are in general designed to a high standard. Inaddition, a number of units in the North Sea have been around

W i r e p a y o u t ( m )

195.0

194.0

193.0

192.0

191.0

190.0

189.0

188.0

187.0

186.0

185.0

0.0 20.0 40.0 60.0 80.0 100.0 120.0Tension (te)

Figure 12 – Example of a Pay-Out/Pull-In Test for a Seized SubSea Sheave

Historically semi-sub drilling units have been subject torelatively frequent mooring line failures. The work reported inthis section shows that it is possible for a carefully set up Rigto have a seriously unbalanced mooring pattern which theOperators might not be aware of. Further information can befound in ref. 5. It is hoped that Pay-Out/Pull-In tests can be

undertaken for other semis to determine how wide ranging orotherwise this occurrence could be.

For long-term moored units it is recommended that a ROVshould double check the line tension balance by measuring X,Y and Z co-ordinates of known points on the line or the touchdown points. This should be done in good conditions and thena back calculation can be done of the line tensions.

Recent Multiple Line Failure IncidentsUnfortunately serious mooring incidents continue to occur.For example, a December 2004 North Sea storm resulted in adrilling rig losing two of its eight anchor chains. The resulting

excessive excursions ruptured the drilling riser.During hurricane Ivan five MODUs broke free from theirmoorings and were set adrift. One of the units was a fifthgeneration rig. Fortunately, as far as can be determined, Ivandid not cause damage to the mooring systems on any of thelong term moored FPSs in the Gulf of Mexico.

Indicative Failure Statistics

Based on the limited response obtained during theinternational survey, it is quite possible that only a fraction ofthe total number of mooring incidents which have occurredoutside the North Sea have been reported. In the North Seathere are statutory requirements for mooring incidents to be

long enough for age related problems to start making anappearance. It thus seems prudent to consider official

statistics for this region to be a reasonable indicator of thelikelihood of mooring line failure. Based on reference 2 forthe 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 9years for a production semi submersible and once every 8.8years for a FPSO. Thus it can be seen that although the failure

probability for production units is approximately half that of asemi-submersible drilling unit, the statistics indicate that itwould not be totally unexpected for the crew on a FPS toexpect a mooring line failure at sometime during a field lifewhich exceeds 9 years. Exactly how these statistics can be

related to milder environments is difficult to quantify at present.

Good Practice Recommendations

In Air-InspectionMobile Offshore Drilling Units (MODUs) need to recovertheir mooring lines and anchors on a regular basis when theymove from one location to another. This provides periodicopportunities to undertake in-air mooring line inspection whenthe vessel is in sheltered water. Alternatively a spare line may

be bought or rented which can be swapped out with one of theexisting 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 FPSmoves off location. It is possible to recover mooring lines partway 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 ofanchor handling and possibly heading control tugs will berequired 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 anunderstandable interest among operators to undertake in-waterinspection. However, there will still be times when anomaliesare identified which can only be resolved with true confidence

by undertaking in-air inspection. One definite advantage of inwater inspection is that it is easy to identify which parts of thechain have been in the thrash zone and at the fairlead. This ismore difficult to determine for long lengths of chain lying on aquayside.

In-Water Inspection

To date chain mooring components have been the subject ofthe greatest effort to develop in-water inspection methods.



9[OTC 17499]

This is because they are typically used in the sections ofmoorings subject to the greatest deteriorative forces,

particularly at the seabed touchdown (thrash zone) and at thevessel interface. Both windward and leeward lines should beinspected, but a particular check for wear should beundertaken on the leeward lines, see Figure 3. Care is needed

when inspecting the touchdown zone, since potential hazardssuch as rocks or debris on the sea-bed can cause mooring lineabrasion. These hazards may be partially obscured by the sea

bed/mooring line and thus good visibility with powerfullighting is required.

In-Water Chain Measurement

A number of in water mooring chain measurement systemshave been developed with varying success, ranging fromsimple diver-deployed manual calipers to a prototype stand-alone robotic system and ROV deployed systems.

Diver inspections are not a favoured option. Mooring chainsare highly dynamic and therefore are potentially dangerouswhen divers are in close proximity. Also diver inspection has

proven to generate inconsistent results and has inherent depthlimitations, for example, when checking the thrash zone.

A stand-alone robotic system has been developed, but so farthis has proven too large and cumbersome for practicaloffshore operations. In addition, it does not appear able toinspect the vital seabed touchdown or get in close to thefairleads.

ROV-deployed systems include both mechanical caliper and

‘optical caliper’ systems. Mechanical calipers have met withlimited success, primarily because during deployment ontochain they have the potential to be knocked out of ‘true’ andconsequently may well have to be recalibrated betweensuccessive measurements.

The most established ROV-deployable chain measurementsystem is effectively an ‘optical caliper’ 7, comprised ofmultiple high resolution video cameras and lights ondeployment frame, which is equipped with scale bars in pre-assigned orientations and at set distances from each other andthe cameras (Figure 13). The system measures the chain

parameters by calibrating from the tool scale bars and

resolving dimensions and optical distortions using offlineimage analysis software.

This type of system has no depth limitation, requires no physical recalibration and can be configured to measure notonly chain components at the seabed, but also in difficult toaccess regions such as the vessel interface. It can also beconfigured to measure other types of mooring ‘jewelry’ suchas connectors, shackles and kenter links.

The ‘optical caliper’ chain measurement technology is usedextensively by offshore operators and is accepted by a numberof 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 FPSfacility.

Figure 13 - Illustration of ROV deployed ‘optical caliper’7measurement system

Loose Stud Detection

In studded chain, loose studs have been implicated in crack propagation and fatigue. Accordingly studded chaininspection and recertification protocols require the assessmentof the numbers of loose studs and degree of ‘looseness.’However, there is no consensual industry opinion with respectto loose stud reject criteria. Traditionally chains have had to

be recovered for detailed loose stud determinations and haverelied on a manual test, either moving the stud by hand orusing a hammer to hit the studs. The resulting resonance (a‘ping’ or ‘thud’) is used to assess whether a stud is loose ornot.

Recently an ROV-deployable loose stud detection system has become commercially available 7. The system uses anelectronically activated hammer to impact the stud and uses ahydrophone 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 loosestuds can be detected using a ROV manipulator or a ROVdeployed high pressure water jet.

Component Condition Assessment

As well as chain dimension checking it is also important toassess link integrity and condition. The overall, or general,condition of mooring components often gives insights into thetypes of deteriorative processes that are at play. For examplesurface 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).



10 [OTC 17499]

Underwater visual condition assessment by ROV is particularly difficult because of the inherent ‘flatness’ of videoimages from standard 2D inspection cameras. With 2Dcameras it is very difficult to distinguish whether a visualartifact on a surface is merely a mark, or a region from whichmaterial has been lost (e.g. a pit).

The shortcomings of 2D video can be addressed by using 3Dvisualization, a long-time goal in the underwater inspectionsector. Over the last two decades a number of 3Dvisualization systems have been implemented but, untilrecently, with limited success due to problems with usercomfort 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 newgeneration of 3D video systems 7. These cameras come in arange 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 assetmanagement, so that it is now easier to access data withouttrawling through hours and hours of video footage 7.

Marine Growth Removal

A key challenge of conducting in-water inspection is gettingaccess to the component(s) to be inspected. Materials whichhave been in sea water for extended periods accumulatevarying levels of marine growth which can be heavy,depending on geography, water depth and season 10, (seeFigure 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 DeployedChain

Cleaning options include manual brushing by divers, rotary brushing with wire or synthetic fibre brushes and ROVdeployed high-pressure water or grit-entrained high pressurewater. Each system has its own pros and cons.

Once marine growth is removed it is possible to conductvarious levels of inspection including general visual

inspection, dimensional measurement and assessment ofmechanical fitness. Unfortunately cleaning off marine growthand scaling by high pressure water jetting may acceleratecorrosion by exposing fresh steel to the corrosive effects ofsalt water. At present there are currently no in-waterinspection methods for mooring components that do not

require the prior removal of marine growth. This represents atechnology gap which warrants further investigation.

The time required to remove marine growth depends largelyon the cleaning option chosen and in light of the cost of ROVvessels, can be a substantial component of the cost of aninspection program. Consequently it is essential that the

planning stage of mooring inspection campaigns shouldconsider the most suitable cleaning options for the expectedconditions.

Line Status Monitoring and Failure Detection

Given the safety critical nature of mooring lines one mightimagine that they would be heavily instrumented withautomatic alarms which would go off in case of line failure.In practice many FPSs are not provided with suchinstrumentation/alarms – see indicative statistics below. Ontype a) turrets in which the chains are permanently locked offunder the hull it is particularly difficult to monitor these linesin a reliable manner. For example, how do you readilydistinguish between mooring line and instrumentation failure,without direct intervention ?

Another factor which makes it difficult to be 100% sure of thecondition of a set of mooring lines is that line breaks do occur

along the sea-bed or in the thrash zone. If this happens theline will drag through the mud until the friction exerted by thesoil surrounding the chain matches the tension in the chain atits sea bed touchdown point. Experience has shown that highline pulls are required to drag large diameter chain through thesea-bed.

The following indicative statistics, based on data from themajority of North Sea based FPSOs, give an indication thatinstrumentation is not as prevalent as might be expected forsuch a heavily regulated region:

• 50% of units cannot adjust line lengths,•

50% of units cannot monitor line tensions in realtime,• 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 Executiveis that Operators should have in place suitable performancestandards for the time taken to detect a mooring line failure.This is particularly important as common mode failuremechanisms such as fatigue or wear are likely to be prevalent

on more than one mooring line and early detection of a line



11[OTC 17499]

failure with appropriate mitigation strategies could preventsystem failure. Depending on the inherent redundancy of themooring spread, the time taken to detect a failure could rangefrom virtually instantaneous detection to detection in a matterof days. It is clearly not appropriate to rely on annual ROVinspection to check if a mooring line has failed. Monitoring

the excursion of a FPS, particularly using differential GPS isinexpensive and will provide mariners with a feel for themooring integrity. But without real time monitoring of theenvironment it is unlikely to indicate a line failure in anything

but storm conditions, unless in deep water. Satellite drift isalso a potential factor affecting the reliability of offsetmonitoring.

New methodologies to detect a mooring line failure typicallyfeature 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 systemsshould be trialed in the near future in the North Sea. Another

option may be a response learning system which takes intoaccount the expected performance in measured weatherconditions. The response will be different if a line fails due toa resulting change in the mooring system stiffness. Such anapproach requires further development work. But if theconcept proves successful this could prove to be a relativelysimple and inexpensive retrofit.

Contingency Planning - Spares and Procedures

Based on the indicative failure statistics reported earlier it isquite conceivable that a FPS may lose a line during itsoperational 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 exampleFigure 15. Hence, to minimize FPS safety and businessexposure in case of line failure, it is believed to be wellworthwhile to have spare lines, connectors and proceduresavailable 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 highspecification installation vessel. Installation/constructionvessels are unlikely to be readily available at short notice andtend to be expensive.

If a line does fail and no spares are available it may be

possible to “mix and match” making use of availableequipment from the established marine supply and rentalcompanies. However, the impact of introducing non standardelements into a mooring system is best considered before afailure occurs. Long term mooring (LTM) shackles shouldideally be used as the connectors, but virtually any type ofshackle including alloy shackles would do in the short term.Repairs of this nature should give time for the procurement ofthe correct equipment, which may take around six monthsdepending on industry demand. Because the mooring systemhas been damaged and then modified, it may be necessary toobtain concessions from the relevant ClassificationSociety/Independent Competent Person (ICP). A reduced

operating envelope may have to be accepted during the periodthat the temporary repairs are effective.

Figure 15 – Purpose designed connector for common link tocommon link chain allowing some compliance in two planes

Maximum Sea State for Continued Production FollowingLine FailureOnce a mooring line fails it is believed to be no longerappropriate to apply the lower damaged system line safetyfactors. This is because, in most instances, the reason for theline failure will not be immediately apparent. Thus with theincrease in loading in the remaining lines there is an increasedchance of a further line failure. Hence, it is recommended thatthe higher intact system line safety factors should be applied.Meeting the intact line safety factors with a degraded systemwill typically result in a reduction of the maximum allowablesea state. Data on the reduction in the maximum operational

sea state in case of line failure should be readily available onall units. The international survey indicates at the present timethis data is not generally available either with the designers oron the units offshore.

Conclusions

Moorings on FPSs are category 1 safety critical systems.Multiple mooring line failure could put lives at risk both onthe drifting unit and on surrounding installations. There isalso a potential pollution risk. Research to date indicates thatthere is an imbalance between the critical nature of mooringsystems and the attention which they receive. On many FPSs

there is an important need to improve the knowledge base ofoffshore personnel on the intricacies of their mooring systemsand their potential vulnerability. This will help to ensure thatmooring systems receive the amount of attention they deserve,

particularly during inspection operations.

The interface between the surface vessel and the mooring linerequires particular attention for all types of FPS. Carefully

planned innovative inspection making use of all possible toolshas been demonstrated to be able to detect problems relativelyearly on before they become a potential source of failure. Theuse of micro-ROVs to gain access to restricted areas notaccessible by conventional ROVs and divers has been part of

the key to this success. The inspection which has been



12 [OTC 17499]

undertaken has shown the importance of achieving compatiblesurface hardness since it affects wear. Unfortunately, at

present chain hardness and wear do not seem to be consideredin any detail.

In situ in-water inspection techniques are continuing to

improve, but further developments are needed to providedimensional data on links away from the inter-grip area and toimprove the marine growth cleaning off speed. At present noin-water techniques exist to check for possible fatigue cracksand the development of such technology should beencouraged. Inspection access needs to be improved anddesign briefs should assign a higher priority to designingsystems which are easier to inspect.

On one long term deployed North Sea unit chain wear andcorrosion in the thrash zone has been found to be significantlyhigher 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 windwardlines. Hence, it appears that more interlink rotation isoccurring on the leeward lines. More data is needed to findout if this is a general finding which could have long termimplications 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 componentswill be reduced by wear, corrosion including pitting and the

possible development of small fatigue cracks. Thus to assesslong term integrity with any confidence it is recommendedthat break tests on a statistically representative sample numberof worn components should be undertaken. Recovered lines

from the thrash zone and from the fairleads/chain stopper areawould be ideal for testing. Such material is likely to beavailable whenever a FPS comes off station or has repairsdone to its moorings. As well as break tests, MPI,

photographs and comprehensive dimension measurementsshould be undertaken. It is important that this data should befed back to the industry. Certain North Sea Operators haveshown a willingness to make this data available.

Offset monitoring has limitations in quickly detecting linefailure unless a FPS is in deep water. However, it is cheap andeasily installed. Hence it should be installed as standard on allunits. In addition, all units should know the maximum sea

state in which they can continue to produce in case one linefails. On board emergency procedures should identify whataction should be taken in case of riser rupture while the risersare still pressurized, although the likelihood of this happeningis low.

A possible contributory mechanism for the relatively highfailure line failure rate among drilling semi-submersibles has

been identified. This is believed to be due to rigs thinkingthey have set up balanced pre-tensions when in fact this hasnot been achieved. Hence, it is recommended that Pay-In/Pay-Out tests should be undertaken to check whether the linetension readings can be relied upon,

Finally a general lack of suitable spare lines, connectors andrepair procedures has been noted. Given the substantial

procurement lead-time associated with these items it isrecommended that Operators should review their assets to seehow they could deal in the short term with one or more failedlines. The reported statistics show that line failures have been

higher than might normally be expected for custom designedsystems 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 followingsupporting organizations is gratefully acknowledged: B.P.,Chevron Texaco, ENI, Norsk Hydro, PetroCanada, Statoil,Bluewater, SBM, Maersk Contractors/North Sea ProductionCompany, 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, BalmoralMarine, BMT/SMS, National Oilwell-Hydralift/BLM,Hamanaka Chains and in particular to Williams MarineEnterprises.

The project Steering Committee itself has been exceptionallystrong and it is hoped that it will be possible for the committeeto continue to meet during future FPSO Forum/JIP Weeks.This will provide a continuing reporting/recording mechanismas more data becomes available. New participants to thiscommittee will be welcome.

References1. “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 20015. “Design and Integrity Management of Mobile Installation

Moorings,” HSE Research report 219, 20046. “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 andJanuary 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

26

APPENDIX D – HSE SAFETY NOTICE 3.2005FLOATING PRODUCTION AND OFFLOADING(FPSO) MOORING INSPECTION

281



Floating Production Storage and Offloading (FPSO) -Mooring Inspection

x Safety notice: 3/2005x Issue date: Apr 2005

Introduction

1. This notice is for operators of monohull weather vaning FPSOs and FSUs. Itexplains why they need to ensure that the top sections of their mooring chains arenot 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 chainwear has been experienced on one UKCS FPSO inside the trumpet connected tothe turret's chain table (spider). Essentially, the mooring chain is directed througha carefully designed trumpet that has the ability to rotate about a horizontal axisand thus accommodate the vertical motions of the FPSO without transferringsignificant 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. Theexact cause of the wear has as yet not been ascertained. Causes might includeinaccurate offshore installation, defective design of the trumpet and/or unforeseenload conditions at the trumpet.

4. The wear experienced is generally manifested as a loss of cross-sectional area. Insome chain links the loss of material has been such that retained strength would beinsufficient to achieve design factors of safety. Furthermore, the deterioration inthe 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 atrumpet. Defects that affect more than one mooring chain can increase the risk ofmultiple 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.



x

x

x

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x

7. Operators should inspect the mooring chains around and inside the mooringtrumpet 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 carriedout based upon the findings of the initial inspection.

Further information

Any queries relating to this notice should be addressed to:

Health and Safety ExecutiveHazardous Installations Directorate

Offshore DivisionLord Cullen HouseFraser PlaceAberdeenAB25 3UBTel: 01224 252500Fax: 01224 252615

This guidance is issued by the Health and Safety Executive. Following the guidance isnot compulsory and you are free to take other action. But if you do follow the guidanceyou 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.

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