TWI_3.1u manual

TWI Tuition Notes for 3.1U Course (DIS 1)

Training and Examination Services Granta Park, Great Abington Cambridge, CB1 6AL UK

Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Table of Contents

Table of Contents TWI TUITION NOTES FOR 3.1U COURSE (DIS 1)........................................................................... 1 TABLE OF CONTENTS........................................................................................................................... 2 PREFACE................................................................................................................................................. 11 THE CERTIFICATION SCHEME FOR WELDMENT INSPECTION PERSONNEL – ORGANISATION AND EXAMINATION........................................................................................................................................ 11 1 The Certification Scheme for Weldment Inspection Personnel (CSWIP)................................ 11 2

TWI.................................................................................................................................................... 11 2.1 Company Profile........................................................................................................................... 11 2.1.1 Single Source of Expertise ...................................................................................................... 11 2.1.2 Non-profit Company ............................................................................................................... 11 2.1.3 Global Benefits........................................................................................................................ 12 2.1.4 Confidential Consultancy ........................................................................................................ 12 3 TWI Certification Ltd ................................................................................................................... 12 3.1 Certification Management Board.................................................................................................. 12 3.1.1 Responsibilities of the Board................................................................................................... 13 3.1.2 The Management Committees:................................................................................................ 13 4 CSWIP Certification for Underwater Inspectors .......................................................................... 15 4.1 Inspector Categories ..................................................................................................................... 15 4.2 The CSWIP 3.1U Examination .......................................................................................................... 15 4.2.1 The Theory Examination......................................................................................................... 15 4.2.2 Practical Examination.............................................................................................................. 16

CHAPTER 1 ............................................................................................................................................. 18 ENGINEERING OFFSHORE STRUCTURES.................................................................................................. 18 1 General Background ............................................................................................................... 18 1.1 1.2

2

Safe to Operate................................................................................................................................... 18 Government Legislation..................................................................................................................... 18

Design Specifications.............................................................................................................. 18 2.1 2.2 2.3 2.4 2.5 2.6 2.7

3 4

Materials ............................................................................................................................................ 18 Working Life ..................................................................................................................................... 18 Loading.............................................................................................................................................. 19 Environment ...................................................................................................................................... 19 Maintenance....................................................................................................................................... 19 Weight ............................................................................................................................................... 19 Dimensions ........................................................................................................................................ 19

Construction Activity Monitoring System ............................................................................... 19 Guidance on Design and Construction ................................................................................... 19 4.1 4.2

United Kingdom ................................................................................................................................ 19 Guidance from the UK Regulations ................................................................................................... 20 4.2.1 Specific Guidance.................................................................................................................... 20 4.2.2 Environment ............................................................................................................................ 21 4.3 Steel and Concrete ............................................................................................................................. 21 4.3.1 Steel......................................................................................................................................... 21 4.3.2 Concrete Structures ................................................................................................................. 22 4.4 Loads ................................................................................................................................................. 22

5 6

Conclusion .............................................................................................................................. 22 Pipelines.................................................................................................................................. 23 6.1

7 8

Pipeline Laying .................................................................................................................................. 23

Offshore Oil Terminals ........................................................................................................... 24 Future Trends.......................................................................................................................... 24 8.1 8.2

Drilling............................................................................................................................................... 24 Design Practices................................................................................................................................. 27

CHAPTER 2 ............................................................................................................................................. 30 OFFSHORE STRUCTURES AND INSTALLATIONS ....................................................................................... 30 1 Introduction ............................................................................................................................ 30 2 2.1

Steel Production Platforms................................................................................................................. 30 Brent A Statistics .......................................................................................................................... 30 Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Table of Contents 2.2

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Terminology ...................................................................................................................................... 32 2.2.1 Basic Components of Steel Platforms ..................................................................................... 34

Concrete and Steel Gravity Platforms .................................................................................... 39 3.1 3.2 3.3 3.4

4

Cormorant A Statistics....................................................................................................................... 40 Disadvantages of Concrete Structures................................................................................................ 40 Basic Components of a Concrete Gravity Structure........................................................................... 41 Common Concrete Components ........................................................................................................ 42

Terminology with Different Offshore Structures..................................................................... 45 4.1 4.2 4.3 4.4 4.5 4.6

5

Jack-up Rigs....................................................................................................................................... 45 A Semi-submersible Rig .................................................................................................................... 46 Drill ship ............................................................................................................................................ 48 Compliant Towers.............................................................................................................................. 48 Tension Leg Floating Platforms......................................................................................................... 52 Floating Production Systems ............................................................................................................. 54

Floating Production Storage & Offloading Units (FPSO) ..................................................... 55 5.1 5.2

6

Reasons for using an FPSO................................................................................................................ 55 Features of an FPSO .......................................................................................................................... 55

Inspection of FPSO systems.................................................................................................... 58 6.1 6.2

Seabed Facilities ................................................................................................................................ 58 Pipelines............................................................................................................................................. 68

CHAPTER 3 ............................................................................................................................................. 76 LOADING ON OFFSHORE STRUCTURES - ENGINEERING CONCEPTS ........................................................ 76 1 General Introduction .............................................................................................................. 76 1.1 1.2

2

Stress.................................................................................................................................................. 76 Types of Stress................................................................................................................................... 77

Properties of Materials ........................................................................................................... 80 2.1 2.2 2.3

3 4 5

Yield Stress........................................................................................................................................ 80 Ultimate Tensile Strength (UTS) ....................................................................................................... 81 Stress Concentration .......................................................................................................................... 82

Crack Stopping or Blunting .................................................................................................... 83 Residual Stresses..................................................................................................................... 84 Forces on a Structure.............................................................................................................. 84 5.1

The Steady Force on a Structure in a Fluid Flow............................................................................... 84 5.1.1 Drag Coefficient ...................................................................................................................... 85 5.2 Vibrational Forces on a Structure in a Fluid Flow ............................................................................. 86 5.3 Wave Loadings .................................................................................................................................. 86 5.3.1 Structural Design for Wave Loadings ..................................................................................... 87 5.4 Structural Response to Wave Loading ............................................................................................... 88

CHAPTER 4 ............................................................................................................................................. 92 DETERIORATION OF OFFSHORE STEEL STRUCTURES .............................................................................. 92 1 General Comments.................................................................................................................. 92 2 Categories of Deterioration and Damage............................................................................... 92 3 Accidental Damage................................................................................................................. 92 4 Corrosion ................................................................................................................................ 93 5 Fatigue .................................................................................................................................... 93 6 Wear........................................................................................................................................ 94 7 Embrittlement.......................................................................................................................... 96 8 Structural Deterioration ......................................................................................................... 96 8.1

Stage One – Production of the Raw Materials ................................................................................... 96 8.1.1 Steel......................................................................................................................................... 96 8.2 Stage Two - Fabrication..................................................................................................................... 99 8.2.1 Steel Structures Fabrication Defects........................................................................................ 99 8.3 Avoiding Problems by Design ......................................................................................................... 100 8.4 Stage Three Installation ................................................................................................................... 101 8.4.1 Possible Damage Caused During Installation........................................................................ 102 8.5 Stage Four In-Service ...................................................................................................................... 102 8.5.1 Steel In-Service Defect Categories........................................................................................ 102 8.6 In-Service Defect Categories That Affect both Steel and Concrete ................................................. 105 8.6.1 Inter-tidal and Splash Zones .................................................................................................. 105 8.6.2 Risers..................................................................................................................................... 105 8.6.3 Conductors and Conductor Guide Frames............................................................................. 105 Issue 1.0 Rev 0 Issue Date 01/09/2006

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Caissons................................................................................................................................. 105 Overloading........................................................................................................................... 106

Repairs to Offshore Structures.............................................................................................. 106 9.1

Welding Repairs .............................................................................................................................. 106 9.1.1 Wet Welding ......................................................................................................................... 106 9.1.2 Hyperbaric Welding .............................................................................................................. 107 9.2 Clamp Repairs.................................................................................................................................. 107 9.2.1 Grout Clamps ........................................................................................................................ 107 9.2.2 Friction Clamps ..................................................................................................................... 107 9.3 Concrete Repairs.............................................................................................................................. 107 9.3.1 Repairs to Concrete ............................................................................................................... 107 9.3.2 Reinforcement Repairs .......................................................................................................... 107

10

Repair Inspection .................................................................................................................. 108

CHAPTER 5 ........................................................................................................................................... 111 DETERIORATION OF OFFSHORE CONCRETE STRUCTURES .................................................................... 111 1 General Comments................................................................................................................ 111 2 Structural Deterioration ....................................................................................................... 111 3 Stage One – Production of the Raw Materials...................................................................... 111 3.1

Concrete........................................................................................................................................... 111 3.1.1 Portland Cement .................................................................................................................... 111 3.1.2 Mixing ................................................................................................................................... 112 3.1.3 Setting ................................................................................................................................... 112 3.1.4 Hardening.............................................................................................................................. 112 3.1.5 The Importance of Water....................................................................................................... 114 3.2 Concrete........................................................................................................................................... 114 3.2.1 Aggregates............................................................................................................................. 115 3.2.2 Water Content ....................................................................................................................... 115 3.2.3 Concrete as a Material ........................................................................................................... 115 3.2.4 Reinforced Concrete.............................................................................................................. 115 3.2.5 Reinforcement Design Philosophy ........................................................................................ 116 3.2.6 Pre-stressing .......................................................................................................................... 117 3.2.7 Production Problems ............................................................................................................. 118

4

Stage Two - Fabrication ....................................................................................................... 118 4.1

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Concrete Structure Fabrication Defects ........................................................................................... 118

Stage Three Installation ........................................................................................................ 119 Stage Four In-Service ........................................................................................................... 119 6.1 6.2

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In-Service Defect Categories That Affect Concrete Structures........................................................ 119 Deterioration Caused By Chemical Attack ...................................................................................... 120 6.2.1 Sulphate Attack ..................................................................................................................... 120 6.2.2 Chlorides ............................................................................................................................... 120 6.2.3 Carbonation ........................................................................................................................... 121 6.2.4 Reinforcement Corrosion ...................................................................................................... 123 6.2.5 Corrosion of Built-in Components ........................................................................................ 124 6.2.6 Cracking ................................................................................................................................ 124

Standard Terminology .......................................................................................................... 125 Additional In-service Defects................................................................................................ 131

CHAPTER 6 ........................................................................................................................................... 135 MARINE GROWTH ................................................................................................................................ 135 1 Introduction .......................................................................................................................... 135 2 Types of Marine Growth ....................................................................................................... 136 2.1 2.2

3

Soft Fouling ..................................................................................................................................... 137 Hard Fouling.................................................................................................................................... 142

Factors Affecting the Rate of Marine Growth....................................................................... 144 3.1 3.2 3.3 3.4 3.5 3.6

Depth ............................................................................................................................................... 144 Temperature ..................................................................................................................................... 145 Water Current .................................................................................................................................. 145 Salinity............................................................................................................................................. 146 Food Supply..................................................................................................................................... 146 Cathodic Protection.......................................................................................................................... 146

CHAPTER 7 ........................................................................................................................................... 149

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Tuition Notes for 3.1U Course Table of Contents CORROSION .......................................................................................................................................... 149 1 Energy Considerations in Corrosion .................................................................................... 149 2 The Corrosion Process ......................................................................................................... 150 2.1 2.2 2.3 2.4

3

The Anodic Reaction ....................................................................................................................... 151 The Cathodic Reaction..................................................................................................................... 152 Seawater Corrosion.......................................................................................................................... 154 Electrochemical Aspects of Corrosion............................................................................................. 154

Electrical Theory .................................................................................................................. 155

CHAPTER 8 ........................................................................................................................................... 159 TYPES OF CORROSION .......................................................................................................................... 159 1 Corrosion Cells..................................................................................................................... 159 1.1

Dissimilar Metal Corrosion Cell ...................................................................................................... 159 1.1.1 The Electrochemical Force Series ......................................................................................... 159 1.2 Concentration Cell Corrosion .......................................................................................................... 162 1.3 Pitting............................................................................................................................................... 163 1.4 Inter-granular Corrosion .................................................................................................................. 166 1.5 Grain Boundary Corrosion............................................................................................................... 167 1.6 Stress Corrosion Cracking ............................................................................................................... 168 1.7 Fretting Corrosion............................................................................................................................ 169 1.8 Erosion Corrosion ............................................................................................................................ 171 1.9 Corrosion Fatigue ............................................................................................................................ 173 1.10 Biological Corrosion................................................................................................................... 173

CHAPTER 9 ........................................................................................................................................... 176 FACTORS AFFECTING CORROSION RATES ............................................................................................ 176 1 Polarisation and Corrosion Rate .......................................................................................... 176 2 Environmental Factors Affecting Corrosion Rates ............................................................... 177 2.1 2.2 2.3

Temperature ..................................................................................................................................... 177 Water Flow Rate .............................................................................................................................. 178 The pH Value of the Water .............................................................................................................. 179

CHAPTER 10 ......................................................................................................................................... 183 CORROSION PROTECTION ..................................................................................................................... 183 1 Corrosion Protection ............................................................................................................ 183 2 Cathodic Protection .............................................................................................................. 184 2.1

Cathodic Protection: The Sacrificial Anode Method ....................................................................... 185 2.1.1 Advantages and Disadvantages of Sacrificial Anode Systems .............................................. 186 2.2 Cathodic Protection: Impressed Current Method ............................................................................. 186 2.2.1 Practical Considerations for Installing ICCP Systems........................................................... 188 2.2.2 Reference or Control Electrodes............................................................................................ 191

3

Using Coatings to Protect the Structure ............................................................................... 192 3.1

4

Paints ............................................................................................................................................... 192

Inhibitors (Controlling the Electrolyte) ................................................................................ 194 4.1 4.2 4.3

5 6

Anodic Inhibitors ............................................................................................................................. 195 Cathodic Inhibitors........................................................................................................................... 195 Adsorption Inhibitors ....................................................................................................................... 196

Corrosion Protection by Design ........................................................................................... 196 Anodic Protection ................................................................................................................. 196

CHAPTER 11 ......................................................................................................................................... 199 CORROSION PROTECTION MONITORING ............................................................................................... 199 1 Monitoring Corrosion Protection ......................................................................................... 199 1.1

2

Inspection Requirements.................................................................................................................. 199

Cathode Potential Measurement........................................................................................... 200 2.1 2.2

3 4

High Purity Zinc Electrodes (ZRE).................................................................................................. 200 CP Readings Utilising Silver/silver-chloride (Ag/AgCl) Electrodes................................................ 201

Current Density Measurements ............................................................................................ 202 Calibration Procedures for Hand-held CP Meters............................................................... 203 4.1 4.2

Necessary Equipment....................................................................................................................... 203 Procedure ......................................................................................................................................... 204 4.2.1 Proving the Calomel Cells..................................................................................................... 204

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Tuition Notes for 3.1U Course Table of Contents 4.2.2 Calibration of the Meter ........................................................................................................ 205 4.2.3 Calibration of a Bathycorrometer .......................................................................................... 205 4.3 Overall Calibration of any CP Meter ............................................................................................... 205 4.4 Calibration of Ag/AgCl Proximity Probes ....................................................................................... 206

5

Operating Procedures........................................................................................................... 206 5.1

Normal Cathode Potential Readings Against Ag/AgCl ................................................................... 207

CHAPTER 12 ......................................................................................................................................... 210 WELDING AND WELDING DEFECTS ...................................................................................................... 210 1 Joining Metal Components ................................................................................................... 210 2 Fabricating Offshore Structures ........................................................................................... 210 3 Welding Processes ................................................................................................................ 210 3.1

4

Flux Shielded Arc Welding.............................................................................................................. 211

Types of Welded Joint ........................................................................................................... 212 4.1 4.2 4.3 4.4 4.5

5 6

The Butt Joint................................................................................................................................... 212 ‘T’ Joint ........................................................................................................................................... 212 Lap Joint .......................................................................................................................................... 212 Corner Joint ..................................................................................................................................... 213 Cruciform Joint ................................................................................................................................ 213

Types of Weld........................................................................................................................ 214 Welding Metallurgy .............................................................................................................. 215 6.1

7

Further Considerations for Weld Control......................................................................................... 217

Welding Terms ...................................................................................................................... 218 7.1 7.2 7.3 7.4

8

Plate Preparation Terms ................................................................................................................... 218 Terms Defining Weld Features ........................................................................................................ 219 Welding Process Terminology......................................................................................................... 221 Welded Nodes and Nozzles ............................................................................................................. 222

Weld Defect Terminology...................................................................................................... 223 8.1 8.2 8.3 8.4 8.5 8.6

9

Cracks .............................................................................................................................................. 224 Cavities ............................................................................................................................................ 225 Solid Inclusions................................................................................................................................ 225 Lack of Fusion and Penetration........................................................................................................ 226 Imperfect Shape ............................................................................................................................... 227 Miscellaneous .................................................................................................................................. 228

Defect Categories and Reporting.......................................................................................... 230 9.1 9.2

Reporting Defects in Welds ............................................................................................................. 230 Dimensional Checking Weld Parameters......................................................................................... 230 9.2.1 The Welding Institute Measuring Gauge............................................................................... 231 9.2.2 Welding Institute Leg Length Gauge .................................................................................... 231

CHAPTER 13 ......................................................................................................................................... 234 PHOTOGRAPHY..................................................................................................................................... 234 1 Introduction to Photography................................................................................................. 234 1.1

2

Light and Photography..................................................................................................................... 235

The Camera........................................................................................................................... 236 2.1 2.2 2.3 2.4 2.5

3

Lens Aperture .................................................................................................................................. 236 Shutter Speed ................................................................................................................................... 237 Relationship between Aperture and Shutter Speed .......................................................................... 238 How Digicams Compare to Conventional Cameras......................................................................... 238 Bracketing – Getting the Exposure Right......................................................................................... 239

Focusing the Camera ............................................................................................................ 239 3.1 3.2 3.3

4

The Lens Focal Length .................................................................................................................... 240 Depth of Field .................................................................................................................................. 241 Framing the Subject ......................................................................................................................... 243

Light and Underwater Photography ..................................................................................... 244 4.1 4.2

5

Colour Absorption ........................................................................................................................... 245 Loss of Light Intensity ..................................................................................................................... 245

Artificial Light for Underwater Photography ....................................................................... 247 5.1

6 7

Electronic Strobe Lighting ............................................................................................................... 247 5.1.1 Strobe Placement................................................................................................................... 247

Close-up Weld Mosaic Photography .................................................................................... 248 Specific Applications for Offshore Photography .................................................................. 250 7.1

MPI Photography............................................................................................................................. 250 Issue 1.0 Rev 0 Issue Date 01/09/2006

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8 9 10

Stereo-photography and Photogrammetry........................................................................................ 251

Specific Requirements for Inspection Photographs .............................................................. 253 ROV Mounted Cameras ........................................................................................................ 254 Recording Photographs and Care of Equipment .................................................................. 254 10.1

Care of Equipment...................................................................................................................... 255

CHAPTER 14 ......................................................................................................................................... 259 THE USE OF VIDEO IN OFFSHORE INSPECTION ..................................................................................... 259 1 The Scope for Video Underwater.......................................................................................... 259 1.1 1.2 1.3 1.4

2

Diver Hand Held.............................................................................................................................. 259 Diver Head (Hat) Mounted .............................................................................................................. 260 Remote Operated Vehicles (ROV)................................................................................................... 261 Fixed Remotely Operated Video...................................................................................................... 262

Types of Video Camera ......................................................................................................... 262 2.1 2.2 2.3

3 4 5 6

Tube Cameras .................................................................................................................................. 262 Silicon Intensified Target (SIT) Cameras ........................................................................................ 263 Charged Coupled Device (CCD) Cameras....................................................................................... 263

Advantages and Disadvantages with Video Recording......................................................... 263 Equipment ............................................................................................................................. 266 Picture Quality...................................................................................................................... 266 How Video is used................................................................................................................. 267 6.1 6.2 6.3 6.4 6.5

Commentary .................................................................................................................................... 267 What to Say...................................................................................................................................... 267 Terms used to Direct Camera Movements ....................................................................................... 267 Video Logs....................................................................................................................................... 268 Care of Equipment ........................................................................................................................... 269

CHAPTER 15 ......................................................................................................................................... 273 ULTRASONIC DIGITAL THICKNESS METERS ......................................................................................... 273 1 Ultrasonic Inspection............................................................................................................ 273 2 Producing Ultrasound .......................................................................................................... 273 3 What Is Ultrasound? ............................................................................................................. 273 4 Frequency of the Wave.......................................................................................................... 275 5 Speed of the Wave ................................................................................................................. 277 6 Types of Ultrasonic Wave ..................................................................................................... 277 7 Waves That Propagate Through Solids................................................................................. 277 7.1 7.2

8 9 10 11

Longitudinal or Compression Waves............................................................................................... 277 Shear or Transverse Waves.............................................................................................................. 278

Surface Waves....................................................................................................................... 278 Velocity of Ultrasonic Waves................................................................................................ 279 Ultrasonic Wavelength.......................................................................................................... 280 Further Effects of Ultrasonic Properties in Materials.......................................................... 282 11.1 11.2

12 13 14 15 16 17 18

The Decibel System ............................................................................................................... 282 The Direction of Propagation of an Ultrasonic Wave .......................................................... 283 Law of Reflection .................................................................................................................. 284 Law of Refraction.................................................................................................................. 284 Test Frequency...................................................................................................................... 285 Ultrasonic Transducers......................................................................................................... 286 Types of Transducers (Probes) ............................................................................................. 287 18.1 18.2 18.3 18.4 18.5

19 20 21 22 23

Acoustic Impedance (Z).............................................................................................................. 282 Acoustic Attenuation .................................................................................................................. 282

Single Crystal Probes.................................................................................................................. 288 Probe Selection........................................................................................................................... 288 Twin Crystal Probes ................................................................................................................... 288 Compression or Zero Degree Probes .......................................................................................... 289 Angle Probes .............................................................................................................................. 289

Couplant................................................................................................................................ 290 The Ultrasonic Beam ............................................................................................................ 290 Principles of Ultrasonic Testing ........................................................................................... 291 Ultrasonic Test Systems ........................................................................................................ 293 Calibration and Thickness Measurement.............................................................................. 293

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Calibration and Reference Blocks .............................................................................................. 294 Reference Block ......................................................................................................................... 294 Calibration Block........................................................................................................................ 294 Calibration Checks ..................................................................................................................... 294

Thickness Plotting................................................................................................................. 295 Digital Thickness Meters ...................................................................................................... 295 25.1

26

Accuracy of the Readings Obtained With a DTM ...................................................................... 295

Care and Maintenance of Equipment ................................................................................... 296

CHAPTER 16 ......................................................................................................................................... 300 INSPECTION METHODS AVAILABLE TO ASSESS UNDERWATER STRUCTURES ....................................... 300 1 Visual Inspection................................................................................................................... 300 2 Video ..................................................................................................................................... 301 3 Photography.......................................................................................................................... 301 4 Cathodic Potential Readings ................................................................................................ 301 5 Ultrasonic Inspection Techniques......................................................................................... 301 6 Magnetic Particle Inspection (MPI) ..................................................................................... 301 7 Radiography.......................................................................................................................... 302 8 Alternating Current Potential Drop (ACPD)........................................................................ 302 9 Electro Magnetic Detection Techniques (EMD or EMT)...................................................... 302 10 Alternating Current Field Measurement (ACFM) ................................................................ 302 11 Flooded Member Detection (FMD) ...................................................................................... 302 12 Summary of Inspection Methods and Their Use ................................................................... 303 13 Taking Measurements ........................................................................................................... 303 14 Linear Measurement ............................................................................................................. 304 14.1 Ruler ........................................................................................................................................... 304 14.2 Magnetic Tape ............................................................................................................................ 304 14.3 Flexible Tape Measures.............................................................................................................. 304 14.4 Electronic Methods..................................................................................................................... 304 14.4.1 Laser and Infra-red Measuring .............................................................................................. 304

15

Circular Measurements......................................................................................................... 304 15.1 15.2 15.3

16

Callipers...................................................................................................................................... 304 Vernier Gauges ........................................................................................................................... 305 Specialist Jigs ............................................................................................................................. 305

Angular Measurements ......................................................................................................... 305 16.1 16.2

17

Protractor .................................................................................................................................... 305 Pendulum Gauges ....................................................................................................................... 305

Dents and Deformations ....................................................................................................... 305 17.1 17.2 17.3 17.4 17.5 17.6

Profile Gauges ............................................................................................................................ 305 Pit Gauge .................................................................................................................................... 306 Linear Angular Measurement (LAM) Gauge ............................................................................. 306 Casts ........................................................................................................................................... 307 Straight Edge .............................................................................................................................. 307 Taut Wire.................................................................................................................................... 307

CHAPTER 17 ......................................................................................................................................... 311 INSPECTION MAINTENANCE AND REPAIR, QUALITY ASSURANCE AND CONTROL, RECORDING, REPORTING .......................................................................................................................................... 311 1 Legislation Relating to Inspection of Offshore Structures .................................................... 311 2 The Importance of QA and QC ............................................................................................. 312 2.1 2.2

3 4 5

Databases and Trend Analysis ......................................................................................................... 312 The Importance of Documentation and Record Keeping ................................................................. 313 2.2.1 Types of Reporting Systems.................................................................................................. 313

Reasons Why Inspection Is Required .................................................................................... 314 Continuity of Inspection ........................................................................................................ 314 Design Stage ......................................................................................................................... 315 5.1

Structural Marking Systems............................................................................................................. 315 5.1.1 Unique Identification System ................................................................................................ 315 5.1.2 The Alpha Numeric System .................................................................................................. 316 5.1.3 The Box Matrix System......................................................................................................... 317 5.1.4 Clock Orientation and Datum Points..................................................................................... 318 5.2 Safety Critical Elements (SCE)........................................................................................................ 319 Issue 1.0 Rev 0 Issue Date 01/09/2006

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Production of the Raw Materials .......................................................................................... 319 Fabrication Stage.................................................................................................................. 320 Launching and Installation ................................................................................................... 320 8.1 8.2

9 10

Base Line Survey ............................................................................................................................. 320 In Service ......................................................................................................................................... 321 8.2.1 Damage Survey ..................................................................................................................... 321

How the Criteria of Non-conformance System is Applied..................................................... 322 Documentation in an Anomaly Based Reporting System ...................................................... 324 10.1 10.2 10.3 10.4

11 12 13 14

Work Scopes and Workbooks in an Anomaly Based System..................................................... 325 Damage Register......................................................................................................................... 326 Data Sheets ................................................................................................................................. 326 Written Reports........................................................................................................................... 327

Verbal Reporting................................................................................................................... 328 Corrosion Protection and Coating Inspection Report Requirements ................................... 329 Procedure for the Close Visual Inspection of a Weld ........................................................... 329 Summary of Other Recording Methods Used Underwater.................................................... 331 14.1 “Scratchboards” .......................................................................................................................... 332 14.2 Sketches...................................................................................................................................... 332 14.3 Photography................................................................................................................................ 332 14.4 Video .......................................................................................................................................... 332 14.5 Radiography ............................................................................................................................... 332 14.6 Casts ........................................................................................................................................... 332 14.7 EMD, EMT and ACFM Incorporating Computer Recording ..................................................... 332 14.8 Sampling..................................................................................................................................... 332 15 Certification of Personnel and Equipment ....................................................................................... 332 15.1 CSWIP Grade 3.1U Diver Inspector........................................................................................... 333

16 17

Equipment Certification........................................................................................................ 333 Inspection Activities in an Anomaly Based System ............................................................... 333 17.1

18

Real Time Data Gathering .......................................................................................................... 334

Decommissioning.................................................................................................................. 334

CHAPTER 18 ......................................................................................................................................... 337 OTHER NDT METHODS USED OFFSHORE ............................................................................................ 337 1 Introduction .......................................................................................................................... 337 2 Magnetic Particle Inspection (MPI) ..................................................................................... 337 3 Radiography.......................................................................................................................... 338 4 Production of Radiation........................................................................................................ 339 4.1

5

X-ray Production.............................................................................................................................. 339

Production of γ Rays ............................................................................................................. 340

5.1

6

Safety ............................................................................................................................................... 343

How the Method Works......................................................................................................... 343 6.1

7

Radiograph Quality.......................................................................................................................... 344

Electro Magnetic Detection Techniques (EMD or EMT)...................................................... 345 7.1

8

How the Method Works................................................................................................................... 346

Alternating Current Potential Drop (ACPD)........................................................................ 349 8.1

9

How the Method Works................................................................................................................... 349

Alternating Current Field Measurement (ACFM) ................................................................ 350 9.1 9.2

10

How the Method Works................................................................................................................... 350 Application of the Technique........................................................................................................... 351

Flooded Member Detection (FMD) ...................................................................................... 351 10.1

11 12

γ Radiographic FMD ................................................................................................................. 352

Ultrasonic FMD.................................................................................................................... 354 General Point for all FMD Readings.................................................................................... 354

CHAPTER 19 ......................................................................................................................................... 357 CLEANING FOR INSPECTION AND PROFILE GRINDING .......................................................................... 357 1 General Comments................................................................................................................ 357 1.1 1.2 1.3

2

HP Water Jets................................................................................................................................... 357 Diving Medical Advisory Committee (DMAC) Advice .................................................................. 358 Management of any Injury............................................................................................................... 359

Standard of Surface Finish ................................................................................................... 359

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Area to Be Cleaned ............................................................................................................... 360 Profile Grinding.................................................................................................................... 360 4.1

Profile Grinding ............................................................................................................................... 361

APPENDIX 1.......................................................................................................................................... 365 EXTRACT OF OFFSHORE TECHNOLOGY REPORT OTH 84 206.............................................................. 365 Category A (Defects) ...................................................................................................................... 365 Category B (Areas of Concern) ...................................................................................................... 367 Category C (Blemishes).................................................................................................................. 371 General Concrete Terms ................................................................................................................ 378 Reporting.................................................................................................................................................... 379

Weathering ..................................................................................................................................... 379

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Tuition Notes for 3.1U Course Preface

PREFACE The Certification Scheme for Weldment Inspection Personnel – Organisation and Examination 1

The Certification Scheme for Weldment Inspection Personnel (CSWIP)

CSWIP is an accreditation body approved by the UK Government’s Board of Trade and Industry. CSWIP is a subsidiary of TWI Certification, which is incorporated into The Welding Institute (TWI). 2

TWI Is a world centre for materials joining technology and is the parent organisation for TWI Certification.

2.1

Company Profile TWI Ltd, the operating arm of The Welding Institute, is one of the world's foremost independent research and technology organisations. Based at Great Abington near Cambridge since 1946, TWI provides industry with engineering solutions in structures incorporating welding and associated technologies (surfacing, coating, cutting, etc.) through Information Advice and technology transfer Consultancy and project support Contract R&D Training and qualification Personal membership

2.1.1 Single Source of Expertise TWI Ltd is the only single source of expertise in every aspect of joining technology for engineering materials - metals, plastics, ceramics and composites. 2.1.2 Non-profit Company TWI is a non-profit distributing company, limited by guarantee and owned by its Members; it is therefore able to offer independent advice. It is internationally renowned for bringing together multidisciplinary teams to implement established or advanced joining technology or to solve problems arising at any stage - from initial design, materials selection, production and quality assurance, through to service performance and repair.

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Tuition Notes for 3.1U Course CSWIP – Organisation and Examination 2.1.3 Global Benefits Over 450 skilled staff are dedicated to helping industry apply all forms of joining technology safely and efficiently. Some 3200 companies and organisations - representing virtually all sectors of manufacturing industry from over 60 countries around the globe - benefit from TWI services. 2.1.4 Confidential Consultancy TWI undertakes contract R & D in confidence for both industry and governments. As a consultant it can offer individual experts or teams able to help solve problems of all kinds related to materials joining. It will send its specialists anywhere in the world at short notice on troubleshooting missions. 3

TWI Certification Ltd This is a TWI Group company formed in 1993.

3.1

Certification Management Board The body with overall responsibility for the activities of TWI Certification Ltd is the Certification Management Board

Professional Board of TWI

Certification Management Board (TWI Certification Ltd)

Membership, Registration & Education Committee

Membership, Registration & Education Committee CSWIP Welding Specialists & Practitioners Management Committee CSWIP Plastics Welders Certification Management Committee Welding Fabricator Certification Management Committee Certification Scheme for Welder Training Organisations CSWIP In-Service Inspection Management Committee

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Tuition Notes for 3.1U Course Preface 3.1.1 Responsibilities of the Board Thus the Certification Management Board: Acts as the Governing Board for Certification in keeping with the requirements of the industries served by the scheme In turn, appoints specialist Management Committees to oversee specific parts of the scheme. The Certification Management Board comprises 12 representatives of industry and other parties with a valid interest in the certification schemes, for example, fabricators, client organisations, design authorities and training associations. This ensures that the certification schemes truly reflect the needs of industry. 3.1.2 The Management Committees: Meet regularly and monitor the administration of the examinations Recommend changes where they are needed if it means that the examinations can be improved to meet the requirements of industry Discuss new certification ideas. It can therefore be seen that CSWIP is a comprehensive scheme, which provides for the examination and certification of individuals seeking to demonstrate their knowledge and/or experience in their field of operation. The scope of CSWIP includes Welding Inspectors, Welding Supervisors, Welding Instructors and Underwater Inspection personnel

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Tuition Notes for 3.1U Course CSWIP – Organisation and Examination

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Tuition Notes for 3.1U Course Preface

4

CSWIP Certification for Underwater Inspectors Requirement documents: all CSWIP examination requirements documents are available free of charge and may be downloaded from the website www.cswip.com.

4.1

Inspector Categories There are four categories of certification in the Underwater Inspector scheme: 3.1U Diver Inspector 3.2U Diver Inspector 3.3U ROV Inspector 3.4U Underwater Inspection Controller (This is an approved course for preparation for the 3.1U examination.)

4.2

The CSWIP 3.1U Examination The examination itself consists of two main elements, a theoretical examination and a practical assessment.

4.2.1 The Theory Examination This consists of 50 multi-choice questions which will include questions on concrete and 5 questions requiring longer written answers, one from each of five sections. 4.2.1.1 The Written Sections: Underwater visual inspection, steel Underwater visual inspection, concrete Recording methods Corrosion protection NDT methods (general knowledge) and ultrasonic digital thickness measurement

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Tuition Notes for 3.1U Course CSWIP – Organisation and Examination

4.2.2 Practical Examination This will consist of the following parts: Visual examination of an underwater steel structure Cathodic potential measurements Ultrasonic digital thickness measurements Underwater photography Use of Video with oral commentary

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Tuition Notes for 3.1U Course Chapter 1

CHAPTER 1 Engineering Offshore Structures 1

General Background

Historically it is true to say that in the initial stages of development of offshore oil platforms the designs evolved from land-based structures and were constructed on site. The engineering design knowledge was either borrowed or extrapolated from traditional fields of civil engineering and naval architecture. During the 1950s, however, new technology began to be developed for this type of structure. Since then many advances have been made particularly in the field of materials. Governments’ legislation in the various host countries with offshore oil has also played a role in shaping the design of production platforms and the various other structures seen offshore. Economics are very important and play a leading role in platform design. For example it is only possible to justify the expenditure for a massive eight-legged steel or a huge concrete gravity platform when the hydrocarbon reserves in a particular field are large enough to not only warrant the initial capital cost but will also guarantee a good income for a long period of time. There is also a growing concern for the environment and this consideration influences certain aspects of structural design. Another factor of prime importance is safety of personnel. There are two facets to this: 1.1

Safe to Operate

The first facet is the usual concern of engineers to design a structure which is elegant if possible, conservative in its use of materials, fit for the design purpose, able to operate for the prescribed length of time, safe to operate and within the allowed budget. 1.2

Government Legislation

The other facet is government legislation. This is put in place to ensure that structures are fit in all aspects, including safety, for the purpose they are designed to fulfil. 2

Design Specifications

The requirements for an offshore platform will necessitate the consideration of a number of factors and involve drawing up DESIGN SPECIFICATION. The full design specification will contain many different factors, but by way of illustration the following list should serve to indicate some factors affecting load bearing and cost. 2.1

Materials

These should be readily available from suppliers in the required form and should meet the requirements of the design specification. 2.2

Working Life

This may typically be 25 years

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Tuition Notes for 3.1U Course Engineering Offshore Structures 2.3

Loading

The platform should provide a safe working environment for the purpose of recovering hydrocarbon reserves. It must be capable of withstanding the loads imposed on it by the drilling and other works performed in and on the work areas and it must withstand the forces imposed by wind and wave action. 2.4

Environment

Open sea conditions will impose very harsh conditions indeed on the entire structure but especially the jacket. Due consideration must be made to the effects of corrosion because of this environment. 2.5

Maintenance

This should be kept to the barest minimum. Due consideration must be given to the underwater maintenance being especially singled out with a view to not only minimising it but also to use the most cost effective means of achieving any necessary works. 2.6

Weight

The weight of the deck modules must be considered so that the jacket can be designed to support this weight. The all-up weight will have ramifications on the cost and on the seabed design of the foundations. 2.7

Dimensions

The size of the structure will be dictated by the work functions required to be carried out and will be strongly affected by the requirements to keep the topside weight to the minimum. 3

Construction Activity Monitoring System

At the same time as the Design Specification is drafted it is possible for the QUALITY ASSURANCE (QA) function to be implemented. This can take the form of an Activity Monitoring System that would compile: Full certification for the location of all components, normally by way of “as built” drawings. This would normally include any concessions, repairs and the actual location of J tube and temporary access holes. Full material certification Non-destructive Testing (NDT) and inspection certification, which would include personnel qualifications. 4

Guidance on Design and Construction

With these engineering requirements in mind as the basic starting point design and structural engineers will be able to obtain guidance as to what minimum standards are acceptable to the appropriate authority or government body whatever country they are operating in. For an example the guidance in the UK sector of the North Sea will be illustrated. 4.1

United Kingdom

There is a history of legislating in United Kingdom waters going back to 1972 when Parliament enacted legislation that provided for the health, safety and Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 1 welfare of persons working on offshore installations. This was “The Mineral Workings (Offshore Installations) Act 1971” “The Health and Safety at Work etc Act 1974” followed this. Subsequently in 1975 “The Petroleum and Submarines Pipelines Act 1975” was enacted, providing for all pipelines and offshore installations not covered by the 1971 act. Using the powers embodied in the 1971 Mineral Workings (Offshore Installations) Act in 1974 the United Kingdom Department of Energy authorised, “The Offshore Installations (Construction and Survey) Regulations 1974” (SI 289). This Statutory Instrument (SI) was followed, in April 1984 by, “Offshore Installations: Guidance on Design and Construction”. The latest amendment to this document was dated 1990 Both of these Statutory Instruments are now superseded as indicated later in this Chapter. 4.2

Guidance from the UK Regulations

The guidance given in the UK regulations in the early 1970s followed good engineering practice and provided design engineers what was then the most up to date basic information as to the forces and loads acting upon any offshore structure, with specific emphasis on the North Sea environment. It is worth examining these regulations in a little detail because a good number of North Sea structures in the UK sector were designed and installed during this period. At that time a distinction was made between Primary Structure and Secondary Structure; Primary Structure was defined as “…meaning all structural components of an Offshore Installation, the failure of which would seriously endanger the safety of the installation. Examples are, for fixed Installations, piles, jacket legs and bracings, concrete caissons and towers, and main deck girders, for a mobile Installation, lower hulls or pontoons, columns, main bracings and deck beams” and Secondary Structure, defined as, “…The structural elements which are not primary structure are secondary structure. Examples are deckhouses, walkways and helicopter decks” The Guidance also specified that the latest edition of any British Standard or Code of Practice should be used where appropriate and further that standards and/or codes other than British may be used provided that the Certifying Authority* was satisfied there was “… an equivalent degree of safety and integrity” *In SI 289 in 1974 and the other legislation in force up to 1996 there were five authorised “certifying authorities”. The current legislation now in force has revoked this authorisation and now requires “verification” not “certification”

4.2.1 Specific Guidance In SI 289 1974 The Guidance gave specific advice on: Clearance above waves (air gap) Hazardous areas Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Engineering Offshore Structures Layout of equipment and systems Fendering Pipeline risers Location of accommodation and working areas Escape routes And various other subjects concerned with the safety of personnel and structure 4.2.2 Environment Environmental considerations were also dealt with in some detail - advising designers to determine parameters on: The speed and direction of winds The heights, periods and directions of waves, the probability of their occurrence and the effect of currents, seabed topography and other factors likely to modify their characteristics The water depth and variations in water level from tide and storm surge The speed and direction of tidal and other currents Air and sea temperatures The extent of snow and ice accumulations The extent to which marine growth may form on the submerged sections of the installation To assist the designer in determining these parameters various tables were provided showing the then, current relevant data. Comprehensive guidance was also given on corrosion protection and site investigations. 4.3

Steel and Concrete

Both these materials were considered in some detail with design parameters indicated for structural and design engineers guidance. 4.3.1 Steel This material may fail in service for a number of reasons as will be detailed in later Chapters. The Guidance notes in the 1970s considered a number of specific items. Fatigue Life Throughout its service life a structure is exposed to environmental loading. This causes cyclic stress variations in its structural members. Of these forces wave loading is the main source of potential fatigue cracking. The calculated fatigue life should be not less than 20 years, or the required service life if this is greater. In most situations the potential fatigue crack is located in parent material (e.g. at a weld toe) and the relevant cyclic stress is accepted as the range of maximum principal stress at the potential crack location. Specific Joint Design Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 1 The objective is to minimise stress concentration areas Buckling This is another prime possibility for component failure and must therefore warrant special attention. The Requirement for Destructive Testing This is considered in order to minimise potential failures and as part of the overall QA. 4.3.2 Concrete Structures As with steel failure in service could occur due to a number of factors some specific to concrete. Limit State Design Limit States Shear Fatigue Deflection Cracking Cover Over Reinforcement Reinforcement Detailing 4.4

Loads

The prime categories of loads are: Dead Loads Imposed (Operational) Loads Hydrostatic Loads Environmental Loads Deformation Loads Accidental Loads As far back as 1974 the Guidance indicated the required minimum considerations for designers to take into account when considering accidental loadings, along with the then current best advise on how best to determine these loads. 5

Conclusion

It is obvious from the examples given here and from common engineering experience that the engineering requirements for offshore structures anywhere in the world will be similar. The only marked changes will be due to local conditions either imposing greater loadings on the structure or perhaps the local environment being more aggressive. The basic engineering will not change but some components may have to be more massive or higher-grade materials may be required to meet these local requirements. Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Engineering Offshore Structures 6

Pipelines

Offshore pipelines are used to transport oil or gas from platform to loading towers or to shore. They are fabricated from high-grade steel pipe (e.g.API-5LX) which is bitumen wrapped for corrosion prevention and coated with a layer of reinforced concrete to provide a weight coating which gives additional protection as well. The sizes normally vary from 50 mm (2”) to 914 mm (36”) and the wall thickness normally varies according to the pressure rating required. 6.1

Pipeline Laying

The methods for laying pipe has evolved since the 1950s and utilises lay barges on which standard 12 m lengths of pipe are welded together along the centre of the specially designed and fitted out deck of the vessel. Each joint is X-rayed and then coated with bitumen and wrapped with a protective sheathing. As new lengths of pipe are added the assembly is fed over the stern and the barge is moved forward, usually by pulling on anchors, which have been laid by an associated anchor-handling vessel. An alternative approach is laying pipe from a reel barge. The earliest application of this technique occurred during World War II when a 76 mm (3”) diameter pipe was laid across the English Channel in Operation PLUTO (Pipeline Under The Ocean). This early application utilised floating reels with the pipeline being unwrapped from them as they were towed along. The modern application requires the pipe to be prepared on land and then wound onto the reel which is mounted on the stern of the reel laying vessel which itself is moored at a specially designed pier. The vessel then proceeds to the required site and lays the pipeline by un-reeling it over the stern as the barge steams forward. The welding and preparation work on land is carried out in a spooling yard, where the pipe sections are supplied in 12 m (40 ft) lengths. These are welded together to form stalks, usually about 518 m (1700 ft) long. All the welds are X-rayed and coated and the stalks are stowed in racks alongside the spooling dock At the start of spooling, the first stalk is moved into the roller system. The end is welded to a stub of pipe on the reel and is pulled onto the reel. The second length is then welded to the end of the first, the weld is Xrayed and coated and the procedure is then repeated for subsequent stalks All welding and loading operations are performed at the shore facility and therefore are less affected by weather conditions The major area of criticality is establishing and maintaining “even tightness” of the wraps on the reel, this is to avoid potential breakthrough of one wrap into another, which would cause damage to the pipe

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Tuition Notes for 3.1U Course Chapter 1 The reeling and un-reeling of the pipe actually causes yielding of the steel and the maximum diameter pipeline that can be laid is 600 mm (24”). See Figure 1.1

Figure 1.1 MSV Norlift, laying the 10in pipeline, between the Neptune and Mercury fields. 7

Offshore Oil Terminals

Large oil tankers are cheaper to run than small tankers. This philosophy of building large tankers was reinforced in the 1950s when the Suez crisis forced tankers from the Gulf to detour around the South of Africa in order to reach Europe. As tanker sizes increased the number of ports that could handle tankers decreased and public opinion was against allowing such tankers too close to inhabited areas. Many solutions were proposed to solve this problem of shrinking docking facilities which included artificial harbours, artificial offshore islands, multiple buoy mooring systems, tower mooring systems and Single Point Mooring or Single Buoy Mooring systems (SPMs or SBMs). The SPM is the most widely used because of its relatively low operational cost, reliability and flexibility. This configuration is illustrated in Chapter 2. 8

Future Trends

The future is likely to see continued development of current trends and techniques in all areas of offshore engineering, with the probability of new techniques being evolved to enable the exploitation of reserves which are currently marginal or beyond the range of present day techniques. 8.1

Drilling

This is a branch of engineering, which has seen numerous developments the results of which have made recovery of reserves more efficient and more effective. Cost reduction and further development of marginal reserves will, no

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Tuition Notes for 3.1U Course Engineering Offshore Structures doubt, cause a continuation of developments of the present techniques and trends. There will surely be, for instance, increased use of: Horizontal Drilling This enables more formation to be exposed to production and reduces reservoir problems such as associated gas and water production. It is useful for thin and tight, low permeability reservoirs. Fewer wells are needed to achieve optimum reservoir production than with conventional drilling Extended Reach Drilling This can reduce the number of platforms required to develop a field as a greater reservoir area can be drained from one central platform. Horizontal distances up to 7000 m have been achieved Slim Line Well Design Involves cost-effective casing design around an optimal production conduit, this can also reduce the number of wells needed to achieve optimum reservoir drainage Rig Automation This will allow several labour-intensive tasks such as pipe handling to be carried out automatically. For instance, on the rig package developed for Norske Shell’s Troll platform, only one driller and an assistant man the rig floor. On a conventional rig, between five and seven people would be needed to carry out equivalent tasks. All pipe-handling operations are carried out from a specially designed control cabin. Removing personnel from the drill floor means more cost-effective and potentially safer operations Temporary (Lightweight) Topsides On Platforms This design can make production platforms lighter and cheaper than traditional platforms, which include permanent integrated drilling facilities. For example, Norske Shell’s Draugen and Troll platforms are designed so that the derrick set can be removed at the end of the drilling and completion phase. Shell’s Gannet Platform is another lightweight design. Figure 1.2 refers

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Tuition Notes for 3.1U Course Chapter 1

Figure 1.2 Gannet Platform North Sea Central Sector Tender Assisted Operations These operations also help to minimise the weight of the production platform by providing most drilling support equipment on a floating anchored, shipshaped tender in calm waters or an anchored semi- submersible unit for deeper or harsher environments. Mobile Drilling Units These are jack-up or semi-submersible rigs, depending on water depth. They can be used to drill production wells (with well completion on the seabed and production pipelines led to a nearby facility) where size and economics of the reservoir do not justify the installation of a platform.

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8.2

Design Practices

Today’s fixed platforms are lighter, slimmer and simpler than the giant platforms built in the 1970s. There is scope for further simplification, for example of topsides, which account for more than half the capital cost of a platform. Figure 1.3 refers.

Figure 1.3 Comparisons of Capital Costs Topside costs can be reduced, for instance by standardising designs and reducing sparing (duplication of equipment). Another option is to examine alternatives to conventional platform designs. Studies of a purpose-built production jack-up unit, a concrete gravity structure and a tripod tower platform have shown that all three are technically viable and could offer cost saving for applications in water depths around 100 m. Greater use of sub-sea satellite technology instead of building a platform can reduce costs, especially where infrastructure already exists nearby which can be used as a “host “platform. As indicated by the relative sizes of the pie charts in Figure 1.3, the capital costs of constructing a sub-sea satellite 20 km from an existing platform are much lower than the costs of constructing an additional platform. However, in such an instance, the long term technical integrity of existing facilities, platforms and pipelines must be ensured, given that they may be in continued use beyond the original design life which was probably in the order of 20 years anyway.

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Tuition Notes for 3.1U Course Chapter 1

Bibliography Engineering Aspects of North Sea Operations The Shell Approach PP Tapper The Gatwick Press The Offshore Challenge Shell Briefing Service A Handbook for Underwater Inspectors L K Porter HMSO The Offshore Installations (Construction and Survey) Regulations 1974 (SI 289) BSI Offshore Installations Guidance on Design and Construction HMSO API Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms American Petroleum Institute Underwater Inspection M Bayliss, D Short, M Bax E & F N Spon

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Tuition Notes for 3.1U Course Chapter 2

CHAPTER 2 Offshore Structures and Installations 1

Introduction

Offshore hydrocarbon deposits may be gas or oil or a mixture of the two. They are found at different depths in the seabed, they are of different sizes and the recovery of the reserves can be easy or difficult depending on the actual geology of the particular well. These factors influence the design of offshore structures and combine to be one of the basic reasons for there being different types of offshore installations. Some of the biggest installations are in the North Sea and consist of concrete “gravity” structures. Then there are the more common steel platforms, which can be of the eight-legged type or may be of a lightweight four-legged variety. There are also jack-up rigs, which are mobile, and tension leg platforms (TLP), which float. Apart from these production facilities there are also, seabed wells, manifold centres and thousands of kilometres of pipelines. Another common structure seen worldwide is the single point mooring (SPM) which comes in a variety of designs, some of which incorporate storage facilities. 2

Steel Production Platforms

With steel fixed platforms the jacket supports the superstructure, which contains all the necessary facilities. The jacket is built in a fabrication yard and if it is a large six or eight-legged jacket designed to support full production facilities it may well have modified legs designed as floats, or additional ballast tanks may be installed so that it can be floated out to the site. Smaller steel structures, which have been designed, and built as a result of advances made in materials, better understanding of the forces imposed on offshore structures and different design concepts are loaded onto a barge which carries them out. Both these types of platform are sometimes referred to as steel piled structures because the jacket is piled into the seabed once it is in the upright position with piles either driven through the legs or positioned around the main legs and driven through pile sleeves, so-called skirt piles. One example of the large fixed production platform is the Brent A, which is installed in ShellExpro’s Brent Field in the North Sea. 2.1

Brent A Statistics

Water Depth

140 m

Substructure Jacket Type

Self-floating steel construction

Number of legs

6

Number of piles

32 (skirt piles)

Weight of jacket

14,225 tonnes

Weight of piles

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Tuition Notes for 3.1U Course Offshore Structures and Installations Superstructure Production capacity

100,000 bbl/d oil and 200-mmscfd gas

Height of deck above sea level

21.7 m

Deck area

2300 m2

Deck construction

Plate girder

Weight of deck

1,507 tonnes

Weight of deck facilities

2,354 tonnes

Weight of modules and equipment

14,762 tonnes

See Figure 2.1

Figure 2.1 ShellExpro’s Brent A Production Platform North Sea An example of a lightweight platform servicing seabed wellheads and facilities is the Gannet A platform in ShellExpro’s Gannet Field in the central North Sea. The structure itself is of the same basic design, but is much less massive than the production platform. Figure 2.2 refers

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Tuition Notes for 3.1U Course Chapter 2

Figure 2.2 ShellExpro’s Gannet Platform 2.2

Terminology

The production platforms are the most massive installations and they may be of steel or concrete construction, steel being the most prevalent. Both types have standard components and a through working knowledge of this terminology is necessary to be able to communicate with other engineers. Much of this terminology also applies to the other types of structures and therefore a review of this topic for platforms forms the basis for a comprehensive working technical vocabulary. See Figures 2.3 and 2.4

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Tuition Notes for 3.1U Course Offshore Structures and Installations

Figure 2.3 Steel Platform

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Tuition Notes for 3.1U Course Chapter 2 2.2.1 Basic Components of Steel Platforms Following is the common terminology for the components making up the steel sub-sea structure, the jacket, which is constructed of steel pipe work and piled into the seabed.

Figure 2.4 A Four Legged Jacket Built For the Compression Platform Installed As Part of CMS 2 Can One of the sections making up a leg Conductor Guide Frame Horizontal sections of framework, which restrain and guide the conductors

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Tuition Notes for 3.1U Course Offshore Structures and Installations Leg The main vertical component, constructed from a number of sections welded together, supporting the rest of the structure Member One of the horizontal, vertical or diagonal components of the jacket Node A point on the welded steel structure where two or more members meet and are joined. Figure 2.5 refers.

Figure 2.5 Typical Node Pile Guides This is a steel cylinder that supports the pile while it is driven into the seabed. Pile guides are mounted in clusters around each leg at various levels. They are often removed on completion of piling operations

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Tuition Notes for 3.1U Course Chapter 2 Pile Sleeves These are long steel cylinders, grouped around the base of the legs into which the piles are located before being driven into the seabed. The tops of the piles should be level with the tops of the sleeves on completion of piling. See Figure 2.6.

Figure 2.6 Pile Sleeves Additional to these components are a number of appurtenances (attachments). The more important of these are: Caissons Open bottomed tubular components terminating at various depths for the purpose of the intake or discharge of water or waste Conductors These are tubes for drilling purposes connecting seabed wells to the topside. Figure 2.7 refers.

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Tuition Notes for 3.1U Course Offshore Structures and Installations

Figure 2.7 Conductors Flowline Bundles Pipe work-bringing oil or gas from satellite wellheads into the platform and containing control lines, product lines and well injection lines See Figure 2.48 Oil And Gas Risers The vertical section of the pipeline extending up the full height of the jacket that used for transporting oil or gas. Production risers carry oil or gas up from the seabed wellheads via the submarine pipelines. Export risers take the processed hydrocarbons down to pipelines. Refer to Figures 2.8 and 2.9 and 2.xx to 2.tt

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Tuition Notes for 3.1U Course Chapter 2

Conductor

Sea level Export or Import Riser

Vertical Diagonal brace Horizontal brace

Riser clamp

Node Pile Pile

Flow-line

Seabed

Figure 2.8 Steel Structure Terminology

Batter

Sea level Export or Import Riser

Conductor Vertical Diagonal brace

Horizontal brace Riser clamp

Node Pile Pile sleeve

Flowline

Seabed

Figure 2.9 Steel Structure Terminology

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Tuition Notes for 3.1U Course Offshore Structures and Installations 3

Concrete and Steel Gravity Platforms

The first gravity structure was installed in the North Sea in the mid-1970s while the first steel gravity platform was installed offshore in the Congo in the late1970s. Steel gravity structures have not proliferated while concrete have. The concept of a concrete structure came about because of some of the problems associated with steel structures, namely the necessity for a large number of heavy and large piles and the corrosion problem with steel in a hostile environment. Concrete gravity structures require no piles and are immune to corrosion. Initially there were perceived additional advantages of storage space within the base cells and potentially huge deck space which could be fitted out in calm sheltered water which in turn would minimise on-site commissioning thus reducing expensive offshore construction manpower.

Figure 2.10 ShellExpro’s Brent D Concrete Gravity Platform North Sea Apart from Brent D illustrated in Figure 2.10 there are numerous examples of this type of structure constructed to different designs, such as Condeep, CG Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 2 Doris and McAlpine Seatank. To give some idea of the scale of this type of platform the main statistics for Cormorant, A which is a four-legged design, installed in the Cormorant Field in the North Sea are detailed here. 3.1

Cormorant A Statistics

Water Depth

150 m

Substructure Storage Capacity

1,000,000 bbls

Caisson shape

Square

Caisson height

57 m

Number of legs

4

Weight in air

294,655 tonnes

Superstructure

3.2

Production capacity

60,000 b/d oil and 30-mmscfd gas

Height of deck above MSL

23 m

Area of deck

4,200 m2

Deck construction

box girder

Weight of deck

5,593 tonnes

Weight of deck equipment

3,593 tonnes

Weight of modules

19,011 tonnes

Disadvantages of Concrete Structures

In spite of the initial optimism for the design of concrete structures it has been found that there are a number of disadvantages for this type of structure. There are stability problems during tow-out to site that have to be counteracted by limiting the topside weight thus reducing the apparent advantage of large deck space fitted out in sheltered waters. The very heavy lift derrick barges now operating are able to operate in comparatively wide weather variations, which has reduced the cost of offshore installations thus limiting the apparent cost advantage of concrete constructions. Concrete as a material cannot withstand tensile forces. This in turn means the use of the base storage cells must be carefully monitored at all times to avoid any possibility of the storage of crude oil causing a build-up of differential loadings between cells thus causing excessive tensile stresses. Also pressure must not be allowed to build up in the cells; vapour pressure must not exceed 2 bar (30 psi). A further consideration is that oil temperature in the cells must not exceed 38o C in order to avoid thermal stresses. Another, problem associated with the storage of crude oil is that if it is not carefully monitored emulsions formed by the inter-action of oil and associated water can accumulate permanently within the cells. Reservoir sand must not be allowed to accumulate and build up either and therefore steps have to be taken to eliminate this from the crude before it reaches the cells. Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Offshore Structures and Installations At least one of the main shafts will house utilities and because it is some 100m tall and very narrow ventilating it is difficult which necessitates the use of breathing apparatus by maintenance staff working there. This in turn makes routine maintenance and operations of the equipment difficult. Stagnant water accumulated in the structure encourages the growth of aerobic bacteria, which consume oxygen, which in turn generates ideal conditions for the formation of Sulphate Reducing Bacteria (SRB). The growth of SRBs in turn leads to the production of Hydrogen Sulphide H2S. This problem necessitates the creation of safety zones and special procedures to avoid risk to personnel.

Figure 2.11 Processing Takes Place on Statoil’s Gullfaks A Platform. North Sea 3.3

Basic Components of a Concrete Gravity Structure

Gravity structures may be made of steel or a mixture of steel and concrete but the most usual material is concrete itself. They are anchored to the seabed by their own mass hence the term gravity. Common features of this type of design are the large diameter columns supporting the deck module and numerous ballast/storage tanks making up the base. See Figure 2.11 and 2.14

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Tuition Notes for 3.1U Course Chapter 2 3.4

Common Concrete Components

Some components are common to all concrete structures. The following list defines a number of these. Anchorage Point This is an essential part of the tensioning components in pre-stressed concrete structures. The anchorage point is cast into the concrete at the ends of the tensioning tendon or bundle of tendons. It grips the tendon and thereby transfers the load from it to the structural concrete. It is commonly encased in protective concrete domes. Figure 2.12 Breakwater Walls Concrete walls in the splash zone, containing cast in holes that dissipate the wave energy and thus protect the structure within the walled area Cachetage Point This is an alternative name for Anchorage Point. Refer to Figure 2.12

Figure 2.12 Cross-sectional Drawing of a Cachetage Point Jarlan Holes A term used to describe the cast in holes in the Breakwater Walls. See Figure 2.13

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Figure 2.13 Close-up Photograph Of A Jarlan Hole Support Columns These are the concrete, or steel, columns supporting the deck module. See Figure 2.14

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Figure 2.14 Support Columns and Support Domes on a Condeep Design Concrete Platform

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Support Domes These are the tops of the tanks at the base of the structure, which may store oil, water or drilling mud. See also Figure 2.15 4

Terminology with Different Offshore Structures

Having introduced the terminology associated with production platforms the discussion should be extended to other types of offshore structures and vessels. There are a number of different configurations for structures that are designed to fulfil different functions. 4.1

Jack-up Rigs

These rigs are used for wildcat drilling, production drilling and workovers. See Figure 2.15.

Figure 2.15 A Three-legged Jack-up Drilling Platform With Tow Still Attached Starting to Jack-up

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Tuition Notes for 3.1U Course Chapter 2 The jack-up platform consists of a main platform, which is watertight (the hull) and floats for transit. Attached to the hull via a rack and pinion assembly are the tubular steel lattice frame legs. The gears lower the legs to the seabed and the hull is then jacked up by this same method to clear the water. On completion of the drilling the whole operation is reversed and the rig is towed away to a different site. 4.2

A Semi-submersible Rig

These are used for the same tasks as jack-ups and may be self-powered or not. Figures 2.16 to 2.18 refer.

Figure 2.16 The Åsgard B Semi-Submersible Production Platform Is Linked To the Semi-submersible Accommodation Flotel Safe Britannia In deeper water the legs of a jack-up platform would be so long as to give concern about the stability of the legs unless they were much larger in section. Therefore this type of rig is not used in water deeper than about 60 m. At greater water depths the semi-submersible platform is employed. The rig has large hollow legs and pontoons, which can be flooded or pumped dry at will, thus ballasting the platform. When moving from site to site the rig is ballasted up to reduce water drag during transit and, when drilling, the rig is ballasted down to improve stability. It does float at all times and therefore when drilling it is kept in place usually by anchors but it may keep position by dynamic positioning (DP). That is the main engines run all the time and computers especially programmed for the task with current data on weather, tide, sea state and various navigation inputs control the thrust to the various thrusters Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Offshore Structures and Installations (propellers) to keep the vessel stationary in the sea directly over one point on the seabed.

Figure 2.17 Delivery of the Åsgard B Hull by the Mighty Servant 3

Figure 2.18 The Turret Of The Åsgard A Floating Production Vessel Merges With The Internal Pipe Work.

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Drill ship

The drill ship is used for the same tasks as a jack-up but in deeper water it is more weather dependant. It is also more manoeuvrable and mobile. See Figure 2.19

Figure 2.19 Drillship Discovery 1 Either DP or anchors normally keep drillships on station dependent on the water depth, site and project parameters. See Figure 2.19 4.4

Compliant Towers

This design is a tall, slim steel structure that is designed to sway slightly, that is complies with the effects of the wave action. The design is conceived as a “halfway house” between fixed and floating structures. It is possible to use the design in water depths up to some 1000 m in moderate environments. The Baldpate GB 260 Platform is located in 499m (1,650ft) of water, in Garden Banks (GB) block 260, 120 miles off the Louisiana coast. This is the first freestanding offshore compliant tower ever, as well as one of the tallest freestanding structures in the world. The tip of the flare boom extends (575m 1,902ft) above the seafloor. Figures 2.20 to 2.24 refer.

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Figure 2.20 GB 260 Compliant Tower Gulf of Mexico

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Figure 2.21 Artist Impression of GB 260 Compliant Tower

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Figure 2.22 GB 260 Base on Tow Barge during Tow out To Site

Figure 2.23 GB 260 Jacket before Float Out

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Figure 2.24 GB 260 Base Launch 4.5

Tension Leg Floating Platforms

Tension Leg Platforms (TLP) consist of a hull anchored to the seabed with vertical tendons. Vertical movement is constrained by the tendons thus allowing production wells to be located on deck. An example of this type of structure is Conoco’s TLP in the Hutton Field in the North Sea which was installed in 1984. This design is suitable for deep-water production and some engineers believe the technology could be extended to water depths of 3000 m. See Figures 2.25 to 2.27

Figure 2.25 Statoil’s Snorre B TLP North Sea Issue 1.0 Rev 0 Issue Date 01/09/2006

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Figure 2.26 Diagrammatic Layout of a Typical TLP

Figure 2.27 Snorre B Anchor Points under Tow Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 2 4.6

Floating Production Systems

Floating production systems (FPS) are a variation on the theme of TLPs and consist of a floating vessel with production facilities connected to seabed wells by flexible risers. Vessels may be purpose built, or converted and may be mono-hulls or semi-submersible. Tankers, for example can be converted for this task relatively quickly and cheaply. In this case they are usually known as Floating Production and Storage Operations (FPSO). These vessels are quite weather dependant, which is why purpose built vessels, have been developed and why semi-submersibles are used for this concept. Semi-submersibles do not have oil storage capacity, which therefore has to be provided separately. FPSs were first introduced in the 1970s and today they have potential for development for deep water drilling. Figures 2.28 to 2.30 refer.

Figure 2.28 The Åsgard A FPSO Measures 278m in Length and Has A Displacement of 184,300t.

Figure 2.29 Terra Nova FPSO

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Figure 2.30 Terra Nova FPSO Schematic 5 Floating Production Storage & Offloading Units (FPSO) FPSOs have been used since 1977 when the first FPSO was installed off Spain. A typical offshore installation is shown in Figure 2.31, 2.32 and 2.36 5.1

Reasons for using an FPSO

FPSOs are used where: The water depth is too great for installing a fixed platform In shallow water locations where the size of the hydrocarbon accumulations are not large enough to make a fixed installation commercially viable In remote locations where export pipelines would be too expensive Where the hydrocarbon accumulations are dispersed so far as to make drilling from one platform not viable. Where weather conditions are extreme, utilising purpose designed units.Features of an FPSO There are a number of common components that are found on any FPSO: Turret see Figure 2.35, to 2.37 Flexible Riser Systems see Figure 2.33Sub-sea Pipeline and Wellhead systems see Figures 2.37Offloading systemMooring systemFigures 2.28 to 2.46 refer

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Figure 2.31 Typical FPSO

Figure 2.32 Tanker Conversion FPSO

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Figure 2.33 FPSO Diagrammatic Layout

Figure 2.34 Flexible Riser Flotation

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Inspection of FPSO systems

Inspection programs for FPSOs revolve around the dry docking program. As these systems are vessels it is usual for them to be dry docked every 5 years. This is not a hard and fast rule in every part of the world as there are arrangements for these vessels to be inspected on site over a longer period than this. Also extensions are possible even on a 5-year regime. However, a typical inspection program would include the following: Mooring and Riser Inspection ROV visual hull survey Specific inspection of all sea chests Turret Inspection Inspect mid-water arch and confirm the lazy S configuration Measurements of individual mooring chain links for wear These inspections should be carried out when the FPSO is loaded in order to video the entire wetted area of the hullMore detailed inspections are normally carried out during refit or dry-dock and include: Eddy current or MPI inspection of specified components Wall thickness measurements in specified areasCP survey and replacement of anodes 6.1

Seabed Facilities

The first sub-sea production Christmas tree was installed by Shell offshore California in 1961. Since then there has been a steady increase in these facilities with the early wellheads being installed and serviced by divers. Developments now allow these tasks to be completed remotely thus, importantly extending the depth range for installation and maintenance. Apart from seabed wellheads there are also manifold centres such as the Underwater Manifold Centre (UMC) in Shell’s Cormorant Field, Linear Block Manifolds (LBM) as installed in Shell’s Osprey Field and Sub-sea Isolation Valves (SSIV) as installed throughout the North Sea. Currently there are more than 650 sub-sea wells worldwide of which approximately one third are installed on the UK continental shelf. These structures can offer advantages over platforms. To reach remote pats of the field inaccessible to the existing platform To develop a field too small to warrant the cost of a fixed platform where process facilities can be provided as required by a floating facility To develop a wide spread field using dedicated FPS and linking the wells with pipelines To develop a number of smaller fields all in the same district again using FPS Some of these facilities are illustrated below. See Figures 2.38 to 2.46 Issue 1.0 Rev 0 Issue Date 01/09/2006

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Figure 2.35 Balder Field FPU

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Figure 2.36 Artist Impression Balder Field Schematic

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Figure 2.37 Balder FPU Turret Being Installed

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Figure 2.38 Machar Field Seabed Manifolds

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Figure 2.39 Dunbar Sub-sea Choke Manifold

Figure 2.40 Schematic Seabed Four Well Layout Issue 1.0 Rev 0 Issue Date 01/09/2006

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Figure 2.41 Gannet Sub-sea Isolation Valve (SSIV) Assembly Installation

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Figure 2.42 Gullfaks Hinge-over Sub-sea Template (HOST)

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Figure 2.43 Renee Field Manifold and Wellheads

Figure 2.44 Snohvit Seabed Wellheads and Protection Frame

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Figure 2.45 Vixen Sub-sea Tree

Figure 2.46 Vixen Wellhead Structure Issue 1.0 Rev 0 Issue Date 01/09/2006

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Pipelines

Pipelines are used extensively for the transport of crude oil and gas and there are many thousands of kilometres of sub-sea pipelines throughout the world. Figures 2.47 to 2.56 indicate some of these facilities and how they are laid. These structures may appear to be simple on an initial cursory inspection but they are carefully designed and a good deal of specialised design effort goes into their construction. Traditional pipelines are constructed of steel and may be made up of nominal 40 foot (12.1 m) lengths of pipe sections up to 3 feet (0.9 m) in diameter which are welded together. Figure 2.47 shows a lay barge in operation. Alternatively smaller diameter steel pipe up to 2 foot (0.6 m) diameter can be laid up onto special reels and then laid in long lengths off the back of specially designed reel-laying vessels. Modern developments in materials have led to the widespread use of composite pipes made up of a variety of polymers. One such pipe is known as “Coflexip”. This type of pipe is commonly laid from specially designed reels off the back of suitable vessels. Figures 2.51 to 2.55 give an indication of reel laying operations. A typical field joint in a pipeline is illustrated in Figure 2.56 that indicates some of the complexities of the design and fabrication of this joint.

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Figure 2.47 Lay barge LB 200 Operating in Dunbar Field

Figure 2.48 Dunbar Field Double Wall Interpipe

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Figure 2.49 Gullfaks Flowline Bundle

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Figure 2.50 Beach Launched Pipeline Bundle Showing PLEM About To Enter the Water

Figure 2.51 A General View of CSO Apache Reel Laying Vessel

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Figure 2.52 Onshore Facilities and Jetty for Fabrication, Preparation and Loading Pipelines onto Reel Laying Vessels

Figure 2.53 Pipe Sections Stockpiled Ready for Fabrication

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Figure 2.54 Pipeline Fabrication in the Sheds at the Pipe Yard

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Figure 2.55 Stern View of the CSO Apache Reel Laying On the Cook Project

Figure 2.56 Diagram of a Standard Pipe Length Field Joint

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Tuition Notes for 3.1U Course Chapter 3

CHAPTER 3 Loading On Offshore Structures - Engineering Concepts 1

General Introduction

When any structure is being designed the engineers will, as a matter of course, consider the forces exerted by wind, water, weight of equipment and working loads. The material that the structure is built from supports these forces. The forces set up stresses within the material. Stress is a convenient way of defining the load a material is required to withstand in such a way that comparisons with the loading on other structures of different sizes and shapes can be made. It also allows comparison with the mechanical properties; for example, how near the working stress of any member is to the yield stress or ultimate tensile stress of the material. Comparisons of stresses in different parts of the structure identify those members that are carrying the heaviest loads. 1.1

Stress

Stress is defined as the Force (or load) divided by the cross-sectional area carrying that load. Stress is denoted by the Greek letter σ (sigma) and is defined mathematically

As a simple example of how the concept of stress is applied consider the following. Figure 3.1 illustrates a connecting rod. The rod experiences a tension force of 700 N (Newton). Estimate the average stress at each of the crosssections P and Q

Figure 3.1 Connecting Rod Diagram

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Tuition Notes for 3.1U Course Loading on Offshore Structures – Engineering Concepts Solution Section P From the diagram the force acting on the section P is 700N outward from the surface. The cross-section area is: A = πr2 =19.6 x 10-6 m2 Then using

F

= σA

= 35.7 MNm-2 Section Q Again from the diagram the force is 700N outward from the surface. The new cross-section area is A = πr2 =7.07 x 10-6 m2 Then using

F = σA

= 99.0 MNm-2 1.2

Types of Stress

When a material is required to support or transmit a load, it does so by creating a force between the atoms of the material by moving them from their equilibrium position. This can occur in a number of ways. Tensile stress This is created in the material when the atoms are pulled apart. See Figure 3.2

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Figure 3.2 Tensile Loading on a Solid Compressive stress This is the exact opposite of tensile stress. The atoms are pressed together as illustrated in Figure 3.3. Usually tensile stresses are thought of as positive (+) stresses and compressive stresses as negative (-) stresses.

Figure 3.3 Compressive Loading of a Solid Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Loading on Offshore Structures – Engineering Concepts Bending stress Structures are sometimes loaded in such a way that there is a mixture of tensile and compressive stresses in it. A simple beam supported at the ends and loaded in the middle is a good example as illustrated in Figure 3.4

Figure 3.4 A Simple Beam with a Point Load The top surface is observed to get shorter as it experiences compressive stresses, and the bottom surface gets longer as it experiences tensile stresses. This type of loading gives a stress distribution that varies from maximum compressive stress on one side, to zero at an unstressed layer called the neutral axis, to maximum tensile stress at the other side. In this type of structure, there are both tensile and compressive stresses. Most braces in platform structures experience this mixture of stresses. Shear Stress Another way in which the atoms can be moved to create a force is when layers of atoms are pushed past each other. This is called shear. Shear stress ( ) is defined mathematically thus

The symbol generally used for shear stress is the Greek letter Shear stress is illustrated in Figure 3.5.

(tau).

o As a note of interest, in general, fluids and gasses at rest, cannot produce shear resistance when stationary, and so are subjected to pressure only, which acts at right angles to any surface.

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Tuition Notes for 3.1U Course Chapter 3 o As well as the shearing action shown in Figure 3.5 most rotating motion is transmitted by shear; for example, the drive shaft of a car or the force to tighten a valve. This is often referred to as Torsion.

Figure 3.5 Shear Loading of a Solid Every material will have a characteristic way of reacting to stress. The particular reaction for a given material will be determined by the material properties. 2

Properties of Materials

Materials are identified by their characteristic qualities such as; hardness, rigidity, conductivity, magnetic or not and so on. In order that engineers can compare one material with another it is necessary to quantify these material properties. Among those properties commonly considered when selecting a material for a particular application are: Stress Strain Young’s Modulus Toughness Electrical Conductivity Thermal Conductivity Density Hardness (wear resistance) There are others but these will serve to illustrate the principle. It is not necessary here to consider all these properties but some comments on those affecting load bearing should be of some benefit. 2.1

Yield Stress

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Tuition Notes for 3.1U Course Loading on Offshore Structures – Engineering Concepts and shape. This will continue while the component is in use, unless the yield load is exceeded. Yield Stress is therefore the stress at which the material will no longer behave wholly elastically. If the loading is continued beyond the yield point, the material will deform and some of that deformation will be permanent. Therefore, if a structure or part of it is dented or bent, this indicates that it has been loaded above the yield stress. 2.2

Ultimate Tensile Strength (UTS)

If loading is continued well into the yield region, it reaches a maximum value known as the Ultimate Tensile Strength (σUTS). Ductile Fracture Attempts to load beyond this value will result in the material failing by ductile fracture. Ductile fracture can be identified by a large amount of local deformation in the region of the fracture. Loading a material beyond its UTS can occur within the material at microscopic sites such that there is no noticeable deformation. This type of failure can be caused by: Brittle Fracture This occurs due to the metal becoming harder locally than the surrounding matrix. This local hardening may be as a result of: o Differences In The Material Microstructure This can occur during either the smelting process or during the welding process. In either case the root cause is incorrect management of the cooling process leading to local quenching. This leaves some of the grain structure in a brittle state. o Hydrogen Embrittlement On an offshore structure hydrogen embrittlement may be caused because of overprotection from an impressed current cathodic protection system. Hydrogen embrittlement may also be caused due to incorrect welding techniques. In either case the fracture surfaces do not display any deformation. Fatigue Fracture Cyclic loading causes this. In a corrosive environment such as seawater a structure will have a design finite fatigue life. The vibrations caused by wave and wind actions as well as drilling operations on platforms apply the cyclic loads. Local components may fail prematurely, however due to macroscopic variations. The mechanism for failure is the cyclic loadings cause metal to become harder locally than the surrounding metal (a form of workhardening). This local brittleness prevents the metal from flexing normally and can lead to failure. The signs of fatigue failure are the same as brittle fracture in that there is no local deformation.

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Tuition Notes for 3.1U Course Chapter 3 This lack of noticeable local deformation has been one of the driving forces behind the development of the science of non-destructive testing which is considered in depth in later chapters. See Figure 3.6

Figure 3.6 Typical Tensile Test Characteristics for Ductile and Brittle Failure 2.3

Stress Concentration

Stress concentration is caused within a material because geometric irregularities magnify applied stresses locally. These irregularities can be large or small including; holes, notches, sharp corners, inclusions and cracks. What is vitally important about a stress concentration is its shape not its size. Professor Inglis first developed the theory of stress concentration at the beginning of the 20th century when studying the cause of the formation of cracks from the corners of hatch covers in the decks of merchant ships. The effects of stress concentration can be illustrated by considering an elliptical hole in a large flat plate made of an elastic material such as mild steel as shown in Figure 3.7

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Figure 3.7 Stress Concentration The applied stress is enhanced locally by a factor of:

Where 2l is the length of the major axis of the hole and r is the radius at the sharper end, the minor axis. This factor is called the stress concentration factor Kt. For a circular hole l = r and the stress concentration factor becomes 3. As r gets smaller compared to l the elliptical hole becomes crack-like and the stress concentration factor increases. 3

Crack Stopping or Blunting

From the discussion above it should be obvious why one of the standard emergency remedial procedures, when a crack has been discovered, is to drill a hole at the tip of the crack. This is often referred to as crack blunting or stopping. Whatever the stress intensity factor is prior to the hole being drilled, Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 3 after the hole is drilled it reduces to 3. This same principle is applied to the toes of welds which are ground out if undercutting is severe and it applies when an inspection procedure calls for crack-like defects to be ground out, thus reducing the l/r ratio and reducing Kt 4

Residual Stresses

Residual stresses are set up within the structure during manufacture. They may have arisen from thermal stresses caused by welding during manufacture or by mechanical stresses set up by force-fitting members of a structure together. It is possible to remove these by a stress relieving treatment. If, for whatever reason, this is either not done, or is incorrectly applied, residual stresses will remain in a material, The working stresses then set up during the operational life of the structure will add to the value of the residual stress. This means that the structure is subjected to a higher stress in service than the design predicted, as the designer would have calculated only the working stress. 5

Forces on a Structure

The stresses on the structure will be affected by the forces that the structure experiences. These are of two types; steady and vibrational. Several different effects produce these forces; for example the weight of the equipment, the reaction of the drilling forces, the hydrodynamic forces due to wind and wave action. 5.1

The Steady Force on a Structure in a Fluid Flow

The steady force exerted by a fluid as it passes a stationary structure is known as the drag force. Therefore if a structure is placed in a current of water (the tide) or air (the wind) it will experience a force in the direction of the flow trying to move it in that direction. This can be illustrated in a simple way by placing a walking stick in a swiftly flowing stream. A holding force must be exerted to keep the stick in position. This holding force is equal and opposite to the drag force on the walking stick caused by the stream. Figure 3.10 Refers

Figure 3.10 Force On a Cylinder in a Steady Flow Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Loading on Offshore Structures – Engineering Concepts The size of this drag force depends on several factors that are related by a simple formula: Drag Force (Fd) = ½ Cd ρ AV2 Where

V is the velocity of the fluid flow

(Note that the force on the cylinder in the flow varies with the square of the velocity. For example, double the flow speed and the drag force is increased four times, treble the flow speed and the drag force is increased by nine times)

A is the projected area at right angles to the direction of the fluid flow (Which for a cylinder of diameter D immersed to a depth h is given by A = Dh)

ρ is the density of the fluid (As water id denser than air, the drag force on a cylinder in water would be greater than that of air flowing at the same velocity.)

Cd is the drag coefficient (This is a number that takes into account the shape of the structure and the roughness of its surface.)

5.1.1 Drag Coefficient For illustration consider a disc of diameter D in a fluid flow of velocity V. If a hemisphere of the same diameter as the disc is fixed on the front of the disc, we find that the drag force is reduced. As nothing else has changed, it means that the drag coefficient of this shape is less than that of a disc. If a cone is now added behind the disc, we find that the drag force is further reduced. Again, as nothing else has changed it means that the drag coefficient has reduced. See Figure 3.11.

Figure 3.11 Change of Drag Coefficient with Shape Issue 1.0 Rev 0 Issue Date 01/09/2006

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Vibrational Forces on a Structure in a Fluid Flow

Consider the example of a cylinder in a fluid flow as outlined in paragraph 5.1 but this time look at the flow pattern behind the cylinder. Figure 3.12 illustrates this. Notice that the flow behind the cylinder is not symmetrical but that vortices are shed alternatively form each side.

Figure 3.12 Von Karmen Vortices Shed From a Cylinder in a Fluid Flow The effect of this is to place on the cylinder an alternating force at right angles to the fluid flow and drag force direction. Figure 3.13 refers.

Figure 3.13 Variations in Side Forces on a Cylinder in a Fluid Flow The cyclic forces generated by the wind and water flowing past the structure causes the vibrations that are so important when considering the fatigue life of a structure. 5.3

Wave Loadings

Waves provide an oscillatory motion to the structure, producing forces that act in addition to the forces produced by tidal currents. These forces deform or try to overturn the structure The waves have a predominant direction for their maximum effect, but can come from any direction, since they are wind generated Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Loading on Offshore Structures – Engineering Concepts Waves produced in a storm are generally short and very confused However, when produced by winds blowing over a long distance, or fetch, the waves tend to moderate into long, high swell waves with a long period A period of 14 seconds produces a wavelength of about 300 m The height of the waves is independent of the period, but depends upon the stability of the waves and the energy content For the purposes of classification by the Duty Holder and for insurance, there are standards for any design; these are based on statistical data. As much information as possible is collected over as long a period as possible on: o Wave heights o Wave directions o Wave periods The analysis of these data produces two main results: The maximum wave to be expected in a given time span, generally a 100 year period. (This is only a statistical quality adopted for design, so more than one of these waves, or even larger waves, might actually occur An energy spectrum of the waves (i.e. the graph of the energy in the waves at different periodic times) 5.3.1 Structural Design for Wave Loadings Structures are therefore designed for two conditions: Static loading, using the maximum 100 year storm wave Dynamic loading, using the energy spectrum Owing to the directional properties of the waves, the structure will be designed and placed so that the largest waves from the predominant direction are taken on its strongest orientation, but all other directions should be considered. Inaccuracy in placing the structure can create loads greater than the design loads in that direction. 5.3.1.1 Static Loads The static analysis based on the 100 year storm wave is straightforward, but requires a great deal of work, since both the direction and position of the wave crest, relative to the structure, will produce different effects on different parts of the structure. A wave, being an oscillatory motion, contains water particles with both velocity and acceleration. The velocity will produce drag forces, as mentioned above The acceleration will produce inertia forces, in the same way as any car that is slowed down requires a breaking force

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Tuition Notes for 3.1U Course Chapter 3 5.3.1.2 Dynamic Loading The dynamic response of a structure can be demonstrated easily by swinging a weight on the end of a string, as a pendulum. If the movement of the hand holding the string varies in frequency so will the deflection of the weight at the other end of the string If the amplitude of the hand movement is fixed and the swing or displacement of the weight is noted, it will be observed that as the frequency of oscillation of the hand increases, so the amplitude of the swinging weight will change o First, the amplitude will increase up to a maximum value, the frequency of the hand movement at this condition will be the natural frequency of the system o Thereafter the amplitude will decrease Another observation is that as the weight displacement increases, the direction of the swing well be the same as that of the hand movement. The motion of the hand and the weight are in phase o Once the maximum amplitude of the weight has been exceeded, it will be noticed that the weight is moving in the opposite direction to the hand movement and the motion is then said to be out of phase o As the frequency of the hand motion is further increased, the amplitude of the weight reduces to almost nothing o The peak displacement of the weight occurs at a point called the natural frequency o This frequency will decrease with increasing length of string and increasing weight o Thus considering the hand movement of this example, at certain frequencies of forcing the displacements produced can be very large 5.4

Structural Response to Wave Loading

When a structure is placed in the sea it will experience a range of wave energies and frequencies causing the structure to deflect As the frequency of the wave energy peak approaches the natural frequency of the structure, so the deflection of the structure increases and with it the stress The further the peaks of wave energy, frequency spectrum and natural frequency are separated, the lower the maximum deflection of the structure The same analysis applies to diving and other floating vessels in heave roll and pitch. Thus vessels designed for use in one part of the world may be unsuitable for use in another, where the frequency spectrum differs.

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Tuition Notes for 3.1U Course Loading on Offshore Structures – Engineering Concepts The natural frequency decreases as the height of the structure increases. Thus new designs of structures developed for open water applications such as the compliant tower and the TLP have natural frequencies below the wave energy peak.

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Tuition Notes for 3.1U Course Chapter 3

Bibliography Underwater Inspection Mel Bayliss David Short Mary Bax Failure of Stressed Materials The Open University

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Tuition Notes for 3.1U Course Chapter 4

CHAPTER 4 Deterioration of Offshore Steel Structures 1

General Comments

As soon as any piece of engineering equipment, such as an engine, pipeline, bridge or offshore structure is brought into service it starts to wear out because of use and if it is not maintained it will eventually cease to operate satisfactorily, either by no longer carrying out the function for which it was designed or by failing in a catastrophic manner. The possible causes of deterioration of an offshore structure including accidental damage, corrosion, fatigue, wear and embrittlement are discussed in this chapter. 2

Categories of Deterioration and Damage

Broadly speaking the modes of deterioration may be classified into 6 groups: Gross structural damage Corrosion and erosion Fouling defects Coating defects Scour Metal and weld defects Specific types of deterioration and damage within these groups may be categorised as: Deformation of the structure caused by impact Loss of concrete matrix through impact or internal flaws Missing bolts Coating damage through abrasion or impact or deterioration Damaged cables or ducts caused by impact or deterioration Unstable foundations through poor geology Missing members caused by accidental damage or failure Debris, which may cause impact damage or create fouling or overload the corrosion protection system 3

Accidental Damage

Engineers will try to anticipate all the different modes of failure when they first design a structure but deterioration due to accidental damage is difficult to design against (this does not prevent the guidance notes for offshore structural design from recommending that engineers in fact do just that). In the United Kingdom safety cases have to be submitted to the HSE for evaluation and assessment in an attempt to prevent accidental damage from being a threat to Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Deterioration of Offshore Steel Structures safety. Because of the difficulties associated with preventative design one of the prime methods for dealing with accidental damage is the implementation and effective execution of reporting procedures for informing the appropriate responsible persons as soon as any accidental damage is caused. This type of damage is also likely to occur on any structure because of the reliance placed on being serviced by boats and helicopters. This presents a real possibility for damage caused by accidents such as collisions and the dragging of either anchors or trawls across seabed installations. Ideally, as indicated above should this type of accident happen it should be reported and surveyed as soon as it happens, but in the past, at least, such accidental damage was mainly discovered during routine inspections, the event not having been reported. There have been numerous examples of this type of damage and just by way of illustration the Northwest Hutton suffered an accident during installation that resulted in a main leg suffering loss of member straightness. An accident involving a stand-by vessel and Brae Bravo resulted in a horizontal member just above the splash zone suffering a similar fate. 4

Corrosion

Because steel is placed in a hostile environment, namely salt water, one of the ever-present deterioration mechanisms on the structure will be corrosion Corrosion takes place in two different ways o First of all, uniform corrosion is the process whereby metal is removed uniformly from all over the surface, so that progressive thinning of the member or pipe wall goes on until the thickness is reduced so as to necessitate the renewal of the component o Secondly, pitting corrosion is a very localised corrosion which takes place in an otherwise corrosion free material, creating a pit in the surface of the material These pits deepen with time and if another failure mechanism does not take over, the pit will penetrate the full thickness of the material, causing leakage in the case of a pipeline or service duct, and so necessitate local repair Corrosion attacks of both kinds are accelerated by erosion, increase in temperature and increase in oxygen content, added chemical attack from biological sources and loading on the member from either external loading or residual stresses caused in manufacture. This last is known as stress corrosion. As corrosion is such an important deterioration mechanism in the offshore environment the entire subject is more fully explained in Chapters 7 to 11. 5

Fatigue

Fatigue is the local failure of the material by crack growth caused by cyclic loading. The cracks can grow from flaws in the material, such as a welding defect or notches caused by accidental damage. Alternatively, they can initiate in regions of highly stressed material, which are brought about by residual stresses or stress concentration. Fatigue cracks can also start from pits created Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 4 by corrosion. This condition is known as corrosion fatigue and is covered in Chapter 8. Fatigue causes more in-service failures of machines, vehicles, bridges and similar structures than any other mode of failure The main reason for fatigue failure being so prevalent, and therefore so important, is that it can occur when the applied stress is significantly lower than the yield stress of the material. Indeed even if the stress intensity is kept below the fracture toughness limit Kic crack growth can occur Fatigue is a cumulative form of failure, in that a crack is initiated at some point of stress concentration and then propagates through the material by acting virtually as its own stress raiser The final fatigue crack is the result of the accumulation of the small-scale events associated with each of a great many load cycles. The fatigue crack thus eventually reduces the cross-sectional area to such an extent that final failure occurs by rapid fracture, often with gross deformation of the remaining un-cracked area Fatigue cracking does not affect the material properties therefore fracture toughness remains unchanged. Different materials do however have varying resistance to fatigue although the experience of service failures and laboratory testing has demonstrated that fatigue is difficult to predict. This is because the process is sensitive to a large number of variables including: o Number of load cycles o Stress or strain amplitude o Mean stress level o Temperature o Environment o Microstructure of the material o Surface condition For design purposes the metallurgist and the design engineer centre their interest on the results of laboratory tests that assess the number of loading cycles N of a given type that the sample survives before fracture occurs. Measurements of N are made as a function of the stress amplitude a. When N is plotted on a logarithmic scale against a the SN curve for the material is obtained and this is used for design purposes. 6

Wear

Wear is normally thought of as the loss of material from surfaces that have been rubbed against one another and it is often measured in terms of the mass lost in a given time under specified conditions. More precisely, wear involves a redistribution of material that adversely alters the surface. In the offshore environment wear is the thinning of material due to uniform corrosion or erosion Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Deterioration of Offshore Steel Structures or a combination of the two. In the wider sense wear can be caused by a number of different mechanisms. Adhesive When two surfaces rub together it causes friction and to explain this it is postulated that some welding of the two contact surfaces occurs within the contact area The mechanism of adhesive wear follows directly from this. When the two surfaces slide over each other material breaks away and does so at the weakest sections. This is found to be the “hills” which make contact as indicated in the sketch in Figure 4.1

Figure 4.1 Adhesive Wear The junctions at which the surfaces are in contact have been strengthened by work hardening and therefore the fractures take place within the materials, at some distance away from the interfaces between the points of contact (the shaded areas in Figure 4.1). Each surface tears out some material from the other and both surfaces become roughened as they gouge and score one another. Wear is rapid and for this reason, in good engineering practise, sliding combinations of similar metals are usually avoided. Abrasive Wear In the mechanism for abrasive wear a hard particle in one surface indents, groves and then cuts material from the other surface. In service, the main cause of abrasion between sliding metals is the presence on one of the two surfaces of particles of hard materials, such as carbide in steels, work hardened wear fragments or hard oxide films. The particles may also be airborne “dirt” such as grit Wear Caused By Fatigue When there is relative motion between two surfaces in contact the state of stress at any given point on or near the surfaces varies with time and this may cause fatigue – the slow growth of cracks. The development of such cracks may eventually detach pieces of material from the surfaces, thereby constituting wear

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Tuition Notes for 3.1U Course Chapter 4 Chemical And Corrosive Wear Chemical effects are most commonly exemplified by the repeating cycle of the formation, removal and reformation of oxides 7

Embrittlement

In this case the material changes its properties from being ductile to brittle. This can be a localised effect. Brittle materials fail due to crack propagation so that they are susceptible to fatigue as well as to brittle fracture. Embrittlement in service could come about due to incorrect welding procedures or by the absorption of a gas, generally hydrogen. Embrittlement has been encountered in natural gas pipelines and could come about from the absorption of hydrogen produced in an overprotected impressed current corrosion protection system. The temperature of the environment affects the brittle behaviour of steel, brittle fracture being more likely to occur at low temperatures This effect is also known simply as Brittle Failure 8

Structural Deterioration

The foregoing paragraphs outline the modes of failure associated with any steel structure and these failure systems will now be put into the context of offshore steel structures. Concrete structures are considered in Chapter 5. A convenient way of illustrating these types of failures is to divide the life of a structure into four stages. At every stage defects leading to deterioration and then failure can occur. 8.1

Stage One – Production of the Raw Materials

During the manufacturing of the raw materials several defects can be included into what will become the parent plate. A selection of possible manufacturing defects are laid out below by way of illustration 8.1.1 Steel Casting defects that can occur Fishtails These may occur in steel produced by traditional mills. During the filling of the moulds while molten steel is being poured into the moulds it is possible for some of the liquid steel to splash up the sides of the mould. This will then cool on coming in contact with the cold sides of the mould and will solidify. The remainder of the steel continues to be poured in and then covers the solidified splashes. When the ingot is removed from the mould, the splashes which form shapes similar to fish tails adhere to the surface. If these fish tails are not removed before rolling they may be rolled into the surface without bonding, thus causing a reduction of material thickness. Figure 4.2 refers

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Figure 4.2 Fishtails Inclusions These will always be present in commercial steels. They are there because of the way iron ore is found and steel is made. The basic ingredient, iron, which usually contains entrapped non-metallic inclusions and typically something over 4 wt% carbon, 1 wt% of both manganese and silicon and there are smaller amounts of both sulphur and phosphorus both of which are highly undesirable. Figure 4.3 refers Because this is the case, in any standard specification the chemical analysis of any “unalloyed” carbon steel will always involve the determination to the “big five”, carbon, silicon, manganese, sulphur and phosphorus, though none of them are likely to be present in any amount exceeding 1.5 wt%. The inclusions present in the steel will become aligned as the steel is subsequently worked and therefore give rise to a so-called fibre structure.

Figure 4.3 Inclusions

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Tuition Notes for 3.1U Course Chapter 4 o In fact silicon and manganese are beneficial as deoxidizers and as solid-solution strengtheners. However, sulphur and phosphorus have an embrittling effect and are usually kept below 0.05 wt% unless deliberately increased to impart specific properties such as machinability Banding And Segregation Steel as it cools from the molten state forms solid grains that will have different chemical compositions and orientations within the forming solid material. This is caused by the way the cooling occurs and in individual grains it gives rise to coring where different sections of dissimilar chemical compositions can be viewed through a microscope within each discrete grain. This effect will also manifest itself within the entire solidifying mass where it can be viewed as bands, which give, rise to its name of banding the results of which is macro-segregation within the material caused by the chemical in-homogeneity. o Banding can become troublesome in alloyed steels where there is more solute to become segregated and where any alloying elements are required to cause a specific response to heat-treatment. Even in unalloyed carbon steels macro-structural segregation of phosphorus, silicon, manganese and carbon may give rise to directional properties. See Figure 4.4

Figure 4.4 Left Micrograph Shows Banding and Right Shows Segregation Laminations Occasionally the structural effects of segregation can become pronounced to the point that the material behaves as if it were made up of different layers. This is referred to as lamination and, particularly in thick sections of approximately 40 mm or greater, can cause serious problems in welded structures where the laminations provide paths of easy crack propagation. This possibility of laminated steels developing internal ruptures is of serious concern to any structural engineer

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Tuition Notes for 3.1U Course Deterioration of Offshore Steel Structures 8.2

Stage Two - Fabrication

While the structure is being built there are a multitude of problems associated with all the aspects of fabrication. Ensuring that the correct materials are being used, verifying the correct fit-up and tolerances are applied and many other specific construction details are important daily tasks for all construction staff throughout the fabrication period of any structure. 8.2.1 Steel Structures Fabrication Defects With steel structures the major fabrication processes involve welding and therefore some of the problems associated with this process will be outlined. There are numerous variables associate with welding and each of these can be subjected to either human or system errors some of which are listed herewith. o Incorrect machining of the angle of bevel o Improper pre-heat treatment o Poor fit-up o Using improper weld consumables o Incorrect storage of weld consumables o Incorrect post-heat treatment These possible faults have to be guarded against during the fabrication stage of any offshore structure During the actual welding process again there are a number of possible weld defects that must be avoided. These are fully explained in Chapter 8. For illustration a short catalogue follows: Lack of root penetration This is a weld defect associated with both submerged arc and manual metal arc welding. Setting too low a voltage with the submerged arc process causes the defect and incorrectly positioning the weld rod is the cause with manual metal arc. In either case the result is a crack-like defect in a very sensitive part of the weld Slag inclusion Another example of a weld defect is slag inclusion. It is possible for this defect to occur when manual metal arc welding is the weld method utilising a multi-pass technique. The cause of the defect is slag from the previous run is imperfectly cleaned off. This leaves isolated pieces of slag that remain and are over-welded by the next run. These inclusions form the sites for potentially dangerous “notches” Porosity This is a weld defect that must always be guarded against. There may be many causes for this fault such as: -

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Tuition Notes for 3.1U Course Chapter 4 o Air contamination of the weld pool o Dirt or damp finding their way into the weld These contaminants breakdown in the weld and produce either; o Nitrogen o Hydrogen or o Carbon Monoxide These gases dissolve in the weld pool and then, as it cools they come out of solution forming gas bubbles, which is porosity in the weld Hydrogen-induced cold cracking This final example of a fabrication defect is a type of cracking normally formed in the Heat Affected Zone (HAZ) some time after the weld is completed. The cracking may occur almost immediately, some hours later or even days after the weld is finished. The cause is hydrogen initially dissolved in the weld pool permeates through the weld into the HAZ in sufficient quantities to embrittle the Martinsitic structure and cause cracking. It is possible for cracks not to occur on cooling but for the hydrogen to make the HAZ more susceptible to crack propagation under in-service loads 8.3

Avoiding Problems by Design

Designers are aware of the problems associated with fabrication and the processes that accompany it and over time have evolved new designs to minimise these problems. It is well known for example that stress is concentrated at any site where there is a sharp change of geometry such as in weld toes and traditional tubular joints. See Figure 4.5.

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Figure 4.5 Stress Concentration Areas As illustrated in Figure 4.5 the stress concentration may be lowered by profiling the weld cap to make the geometry more contoured and less angular. By alterations to the design concept the stress concentration areas may be removed from the nodal areas by utilising cast joints thus removing the welding to less highly stressed regions. Figure 4.6 refers.

Figure 4.6 Cast Node 8.4

Stage Three Installation

Steel structures are commonly constructed on their side and then floated into position where they are rotated to the upright position by flooding ballast compartments in the jacket legs. This rotation imposes a bending moment on the structure that may impose stresses on the structure that are transiently Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 4 greater than the working stresses the structure will subsequently withstand. Of course the flooding operation is conducted as carefully as possible and some modern steel structures have been positioned with the ballast tanks pre-flooded to minimise the stresses involved. The method is illustrated in Figure 4.7, which shows the sequence of events with a “self-floating structure.

Figure 4.7 Self-floating Structure 8.4.1 Possible Damage Caused During Installation At any time during the launch and installation stages of the structure damage may be caused through, accidents, piling operations, grouting defects, stress induced failure, seabed anomalies. There is always a possibility of the structure being out of its final position or being out of final orientation. 8.5

Stage Four In-Service

This is the stage in the life of a structure where underwater inspection first becomes pre-eminent. The major categories of defects that cause concern are outlined below. 8.5.1 Steel In-Service Defect Categories Fouling This term covers both marine growth building up on the structure and debris collecting on and around it. Fouling may cause structural damage, galvanic corrosion, see Chapter 8, overloading of the CP system and may cause safety hazards to divers and ROVs. Coating Damage All types of coatings, paint, bituminous, epoxy, metallic may suffer from defects caused either when they were applied or subsequently because of deterioration or accidental damage. See Chapter 10 Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Deterioration of Offshore Steel Structures Cracks These may be caused by latent flaws initiated during any of the earlier stages in the life of the platform. They are certainly associated with welded joints especially on nodal areas and cracking may be the end result of a defect initiated at the fabrication stage. As stated earlier in this chapter, fatigue is the major cause of component failure in-service. An example of this type of damage is conductor guides that failed due to fatigue cracking on one North Sea structure. The failure is illustrated in Figure 4.8

Figure 4.8 Failure of a Conductor Guide o This type of failure may be avoided if the crack is identified at an early stage, before it propagates. It can be considered to be a “notch” at this stage and profile grinding will remove this effect. This will reduce the weld throat thickness and the wall thickness, however provided this is kept within design parameters and a smooth profile is achieved the possibility of failure is more remote. Profile grinding is more fully discussed in Chapter 19 Corrosion This is a most important form of structural deterioration and it is examined in detail in Chapters 7 to 11. A great deal of underwater inspection effort goes into monitoring corrosion

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Tuition Notes for 3.1U Course Chapter 4

Physical Damage This form of deterioration is generally caused by either collision or impact damage caused by components being dropped. As mentioned earlier all accidental damage, indeed any incident, should be reported immediately so that it can be assessed. Figure 4.9 illustrates damage caused to a horizontal diagonal member by a 24 m length of caisson pipe that had fallen off from three levels above and pierced through the member. No one on the platform was aware that anything had happened.

Figure 4.9 Sketch Indicating Damage Caused By A Caisson Section That Failed In Service Scour The foundations of a structure are an obvious area susceptible to movements of material on the seabed. Any movement is likely to weaken the foundations which, of course, jeopardises the whole structure

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8.6

In-Service Defect Categories That Affect both Steel and Concrete

The in-service defects enumerated for steel can also affect concrete. Concrete structures may suffer from cracks, the reinforcement may corrode, physical damage is certainly possible and scour is also quite possible. Cracks in the concrete surface are less serious than cracks in steel because, as indicated in the concrete section, offshore structures fall into the prestressed category and major components are therefore kept in compression. There are other considerations that do affect both steel and concrete structures and that may cause defects in service such as detailed following. 8.6.1 Inter-tidal and Splash Zones The inter-tidal and splash zones on any structure are regions of particular susceptibility to deterioration. Corrosion is more aggressive in this area and must be more carefully monitored Marine Growth build-up is greater in the top 30 m of the sea and is particularly dense in the inter-tidal region. This increases mass and drag in a part of the structure, which can be more vulnerable to these effects. Marine growth may also affect corrosion rates The risk of physical damage is greater in this region due to the risk from floating objects and, in those parts of the world that are susceptible, icebergs may collide with the structures. Certainly this is possible offshore Canada for example 8.6.2 Risers These components are common to both types of structures, although on concrete platforms they may be installed inside the shaft it is not uncommon to have them mounted externally as well. These items are considered as part of the associated pipeline and therefore are inspected annually because they can suffer the same deterioration as the pipelines. The clamps, guides and flanges are subjected to the same regime. 8.6.3 Conductors and Conductor Guide Frames As with risers these components can be common to all platforms and they are exposed to the same risk of failure as risers, perhaps more so as there are greater vibrations possible with these components than the rest of the platform. Furthermore conductors are normally kept in place by guides rather than clamps which allow relative movement between the conductor and its guides; hence wear must be monitored and is a real possibility for fatigue cracking to occur. 8.6.4 Caissons Caissons are another group of components that are carefully monitored on an annual basis. There is a common problem with this component when it is used as a pump caisson. The pump is commonly suspended from the surface inside the caisson. It is common for the pump to be at about 18 m water depth level Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 4 inside the caisson. Conditions therefore at this point on the inside of the caisson are near perfect for corrosion to progress at excessive rates. This has caused component failure on more than one occasion. 8.6.5 Overloading Changes in the working practices and other commercial factors may lead to extra items of equipment being installed, such as a newer, bigger crane. This may lead to overloading if not carefully monitored. 9

Repairs to Offshore Structures

When any defects are identified on offshore structures the Duty Holder’s engineering department will make a decision on what course of action to take depending on the severity of the defect and its position on the structure. It may be that increasing the inspection effort monitors the defect or it may be repaired. The types of defect that may be identified are: Welding defects Impact damage Fatigue damage Corrosion Welding defects will normally be the most sensitive items and remedial action is therefore more likely with this type of anomaly Impact damage may well be monitored as indicated earlier in this chapter. Fatigue damage is the most difficult to identify and component failure may well occur before this type of defect is identified. This type of defect is also very difficult to predict. This type of discontinuity will be the subject of a repair. Corrosion consumes metal in the corrosion process and reduces the wall thickness of the structural members. Corrosion is such a serious consideration for offshore structures that the subject is dealt with fully in chapters 7 to 11. 9.1

Welding Repairs

Underwater welding repairs may be completed by wet welding or by deploying a hyperbaric chamber and using dry welding procedures. 9.1.1 Wet Welding Wet welding has been used underwater for at least the last 70 years. However due to the problems associated with it such as: Uncontrolled cooling rate Brittleness caused by the quenching effects of the water Lack of sidewall fusion Lack of inter-run fusion Hydrogen embrittlement This technique has, until recently, only been considered to be a temporary repair or a non-structural repair to low stressed components. Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Deterioration of Offshore Steel Structures However, in the last few years there have been advances in wet welding and currently techniques are available that may be used for structural repairs. To date this has only been achieved under test conditions. 9.1.2 Hyperbaric Welding This technique requires that a hyperbaric chamber is sealed onto the repair site and the weld is then completed in dry conditions. The actual weld technique is frequently the TIG method. Specially qualified welder divers are employed to complete the weld. 9.2

Clamp Repairs

Two types of clamps may be used for repairs. Grout Clamps Friction Clamps 9.2.1 Grout Clamps These are used to repair pipeline leaks and node joints. The clamp is positioned and once it is in place with the bolts tightened the annulus is pumped full of grout which completes the repair. 9.2.2 Friction Clamps These are fitted by bolting on and will be manufactured to close tolerance so that when the bolts are tighten the repair clamp offers a proper stress path for the loads imposed on the repaired area. This type of clamp is fitted to at least one offshore structure where it has been in place for some 20 years without further deterioration of the structure. 9.3

Concrete Repairs

Repairs to concrete structures may require a repair to the concrete, or both the concrete and the reinforcement. 9.3.1 Repairs to Concrete Small repairs may be accomplished with resin and at least one North Sea structure has been repaired in this manner. This type of repair is normally only undertaken on small but significant defects. Large repairs may be completed using either grout or concrete. 9.3.2 Reinforcement Repairs Repairs to the reinforcement will require either: Welding Mechanical coupling Steel plates Grouted connections In all cases the passivation of the reinforcement must be recovered if the repair is to last for a significant period.

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Tuition Notes for 3.1U Course Chapter 4 10 Repair Inspection All repairs will be inspected to ensure compliance with the procedure, that the repair work is of the required standard, the damage register is maintained up to date and that engineering confidence in the structure is maintained.

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Bibliography A Handbook for Underwater Inspectors L K Porter HMSO Underwater Inspection M Bayliss, D Short, M Bax E & F N Spon

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Tuition Notes for 3.1U Course Chapter 5

CHAPTER 5 Deterioration of Offshore Concrete Structures 1

General Comments

This chapter looks at concrete as a building material suitable for offshore structures. Following the format of Chapter 4 the various modes of deterioration will be considered. Effects such as accidental damage and fabrication defects may occur with concrete in similar fashion to steel and generally the comments made in Chapter 4 regarding these items apply. Otherwise this chapter will concentrate on aspects of deterioration specific to concrete 2

Structural Deterioration

The format of illustrating types of failures by dividing the life of a structure into four stages laid out in Chapter 4 will be continued in this chapter. 3

Stage One – Production of the Raw Materials

The fabrication of concrete structures has the potential for producing several defects included into what will become the concrete matrix surrounding the reinforcement. A selection of possible manufacturing defects are laid out below by way of illustration 3.1

Concrete

This is a composite material consisting of cement, fine aggregates and coarse aggregates. The cement is the binding agent and contains the reactive agents; therefore this will be examined first. 3.1.1 Portland Cement This is the most popular and therefore most important of the cement binders and the comments made here will be confined to this material. This type of cement is made up of a mixture of about 75% limestone (CaCO3) and 25% clay, which is principally aluminosilicate; it does have a significant iron and alkalioxide content. These raw materials are ground together and fed through a kiln where various chemical reactions occur. The resultant constituents are laid out in table 5.1

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Constituents Of Portland Cement Compound Name

Shorthand Nomenclature

Mineral Name

Tricalcium silicate

C3S

Alite

Dicalcium silicate

C2S

Belite

Tricalcium aluminate

C3A

Aluminate

Tetracalcium aluminoferrite

C4AF

Ferrite

Hydrated calcium sulphate

CSH2

Gypsum

Table 5.1 Constituents of Portland Cement 3.1.2 Mixing When water is added to the cement hydration begins and two things happen; the mix is transformed into a paste and heat is evolved in an exothermic reaction 3.1.3 Setting The first stage in the process of forming concrete into a structural building material once the water is added to form the paste it is called setting. The setting period is the length of time the mix remains workable The setting period will last for a few hours during which time heat is evolved at a very high rate, reaching a maximum of approximately 200Wkg-1 at about 30 seconds, and then falling to a low value. During this period the compressive strength is barely measurable The pH value of the mixture also rises very rapidly during the first minute after water is added, starting at about 7 going up to a maximum of about 12.9 after about 3 hours and then settling to a constant 12.6 o

Its pH number specifies the acidity or alkalinity of any aqueous solution. This is a measure of the concentration of hydrogen ions present in the solution. This is commonly written in shorthand form by using square brackets [H+]. The pH number is defined by: pH = log10 1/ [H+] Or pH = -log10 1/ [H+] Hence pH 1 is extremely acidic and pH 14 is extremely alkaline. Pure water, which is neutral, has a pH value of 7. There is a fuller explanation of the pH system in Chapter 6

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Tuition Notes for 3.1U Course Chapter 5 In the hardening period heat is again evolved reaching a peak of about 1% of the initial exothermic maximum after about 10 hours. The compressive strength increases during this period, the process continuing over a number of years until it reaches its maximum of some 50 MNm-2 after about 27 years. During the hardening process silicon ions form together to form polymers, this reaction is exothermic which goes some way to explaining the heat output during hardening. The sequence of events during the hydration process is thought to be: On adding water to the cement there is an initial period of about one minute of very rapid hydration, with C3S and C3A being the main reactants. This is accompanied by a high rate of heat evolution, silicate polymerisation and a rapid increase in [OH-] which causes a similar rise in the pH number The reaction rate then slows dramatically as the surface cement grains become coated with silicate and aluminate gels. Concurrently the gypsum dissolves so that [Ca2+] and [SO24-] both increase rapidly to a peak after about 2 minutes This peak and subsequent fall is due to the formation of ettringite which is a fine, needle-like crystal phase The cement paste cohesion during the setting period is due to gel-to-gel contact between adjoining grains. This is increasingly aided by the formation of ettringite crystals The gel coating is permeable to Ca2+ and OH- both of which diffuse out during the setting period thus increasing the pH number. At the same time water diffuses in continuing the hydration of the cement grains. The silicates and aluminates do not diffuse through the gel coat but either add to it or build up in solution inside it, thus they are not present in the liquid outside The water inside the gel coating eventually builds to such a pressure that the coating ruptures, and then peels away from the grain forming gel foils and fibrils and also some tubules. The grain locally is then exposed to contact with the outside liquid and further hydration continues As each grain sprouts multitudes of these fibres they grow and multiply and start to interlock and the paste starts to harden. Concurrently with this Ca(OH)2 precipitates out of the supersaturated solution and forms portlandite which is a plate-like hexagonal crystal The continued hardening of the cement comes from the multiplication, growth and interlocking of gel fibres and crystal species such as portlandite. Over a longer time scale C2S participates in the hydration process forming the same products as C3S but developing more slowly and long-term polymerisation of the silicate in the gel all contributes to the hardening process, as does the gel drying out below its saturation point Summarising the parts played by the individual constituents then: Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures Alite Major ingredient, initial gel formation contributes to setting, hydration products, fibres and crystals, make a major contribution to strength, particularly in the early stages of hardening Belite Same hydration products as Alite but reacted more slowly, contributes to increase in strength at later stages of hardening Aluminate Contributes to setting through gel and ettringite formation, but contributes little to hardening Ferrite This along with Aluminate acts as a flux in the cement kiln during the initial manufacture of cement powder. Its hydration products play little part in either setting or hardening. It gives colour to cement Gypsum Controls the hydration rate of the Aluminate and is a constituent of ettringite which contributes to setting. 3.1.5 The Importance of Water Water is an important constituent of concrete firstly because of the hydration process but also because it materially affects the final strength of the concrete. Pores form in the interstices between fibres and between fibres and crystals and these invariably contain water. This gel water constitutes some 15% by weight of the hydrated cement. Combined chemically with the hydrated compounds in the cement is a further 25% by weight, which means that some 40% by weight of water is required for complete hydration. The pores are basically responsible for the tensile strength of concrete being only about 10% of its compressive strength. Excessive amount of water in the initial mix have other effects on the final material. Both compressive strength and stiffness decrease with increasing watercement ratio The stiffness increases with increasing hardening time The stress-strain curves are non-linear. The Young’s Modulus has no unique value, which is the same as with polymers. This means that either a secant or a tangent modulus is used 3.2

Concrete

Concrete is made by adding cement to aggregates and mixing them together to form a versatile building material. Composite materials normally display material characteristics that are better than the characteristics of the individual constituents. With concrete the composite can be considered in two ways:

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Tuition Notes for 3.1U Course Chapter 5 Either the aggregates toughen the cement paste by introducing numerous weak interfaces into the material Or the cement paste provides the means of binding together the aggregates into a low cost useful material The actuality lies between the two. 3.2.1 Aggregates In a concrete mix the aggregate consists of a mixture of sand, with a mean particle size of less than 2 mm, and crushed rock or gravel, with a mean particle size greater than 2 mm. There must be sufficient cement paste to bind these materials together and using graded aggregate that contains particles of a range of sizes can in fact reduce this. The small particles fit into the spaces between the large particles and the cement only has to flow into any remaining spaces. In this case the usual ratio of aggregate to cement is about 5:1 and the typical proportion of sand to gravel is about 3:2. The actual shape of the stones in the gravel affects the final mix. Stone crushed from quarried stone will be angular and give a stronger but less workable mix than stones from river gravel which are smooth and rounded giving a more workable mix but with less strength. 3.2.2 Water Content Water content is as important in the concrete mix as it is in cement mixes. A mix containing 40% water by weight will be totally unworkable but concrete with a high water: cement ratio will result in a lower strength material than a similar mix made with a lower ratio water: cement. This is because quite large pores can develop if compaction is inadequate. It can be seen from this that the actual water content of any mix is very important and must be high enough to allow the mix to be worked but at the same time be low enough to allow the concrete to attain its full strength. One method of overcoming this problem is to use flow-enhancing admixtures (plasticizers) which can keep the water:cement ration low 3.2.3 Concrete as a Material Concrete as a material can be compared to stone in that it can withstand compressive loads very well indeed but it cannot withstand tensile loads. As a building material then it is only safe to use it in situations where it is subjected to compressive stresses only. Its big advantage over stone is that it can be cast on site into almost any required shape. 3.2.4 Reinforced Concrete In order to exploit concrete as a building material to its full potential steel reinforcement bars made from mild steel, which has been heavily cold-worked, are combined with it. This reinforcement may be assembled into quite complex shapes on site prior to the concrete being poured. Shuttering is then used to retain the required shape while the concrete is setting. The complex reinforcement is the result of having to resist stresses other than, for example, the main tensile stresses due to bending. See Figure 5.2

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures

Figure 5.2 Placement of Reinforcement to Counteract Crack Formation 3.2.5 Reinforcement Design Philosophy A point to note in reinforced concrete structures is that if full advantage is to be taken of the high strength of the steel reinforcement that surface of a beam, for example, which is under tensile stress is allowed to crack. This allows the steel to carry all the tensile forces. This also explains the placement of the reinforcement in Figure 4.7, which is positioned close to the surface that is under the tensile load. This leads to one problem with reinforced concrete, which is that the concrete on the tension side is cracked which means that it is doing no Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 5 work and therefore represents a weight penalty on the structure. Additionally vibrations and environmental forces can cause the cracks to open and close repeatedly which leads to gradual deterioration and crumbling of the concrete and may expose the reinforcement to corrosion 3.2.6 Pre-stressing A way to overcome the problem of cracking is to ensure the entire structure is kept in compression. This is known as prestressing. There are two techniques prestressing and post-stressing. In both cases high-tensile steel wires with a tensile strength of 1500 to 1800 MN m2 are employed to apply compression. The technique can be applied in a factory environment in the manufacture of standard prestressed components that can be transported to the site Or the method can be applied on site. In this case the technique is posttensioning and the cables are laid through ducts deliberately left empty for the purpose. The cable is then tensioned up and the duct filled with grout under pressure. Figure 5.3 refers.

Figure 5.3 Diagram of a Prestressed Beam

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures 3.2.7 Production Problems The forgoing will serve to introduce concrete as a material and a selection of possible production problems will serve to illustrate what may go wrong at the manufacturing stage. Too much water in the mix can result in a loss of both compressive strength and stiffness and by creating large pores within the matrix it may promote in-service cracking A reaction between the alkalis in the cement and susceptible, mainly siliceous materials, in the aggregates is a possibility. This expansive reaction is known as alkali/aggregate reaction (AAR). The process is quite slow taking a number of years to develop. The symptoms in the latter stages are cracking and spalling. This is not a problem on offshore structures as the quality of manufacture was and is high. There have been no reports of this defect on any offshore concrete structure to date Exudation is a viscous, gel-like material, which can form a deposit on the surface of the concrete. As this is associated as a symptom of AAR it is unlikely to be seen on offshore structures as indicated above and the more-so as it may be dissolved in the seawater anyway Rust stains are possible on these structures and the worst-case scenario is that it indicates corrosion of the reinforcement. There could be other causes however, such as corrosion of embedment plates or even nails cast into the surface being left over from the shuttering operation. This is a possible serious anomaly and therefore rust stains must always be treated seriously Incrustation, which is caused by the leaching of lime from the cement, will leave a white crusty deposit on the concrete surface. Once more this is unlikely to be identified on offshore structures due to the QC at manufacture and the possibility of the deposit being dissolved by the seawater 4

Stage Two - Fabrication

Comments made in Chapter 4 regarding fabrication problems apply to concrete, of course, and items specific to concrete are enumerated here 4.1

Concrete Structure Fabrication Defects

There can be numerous fabrication defects with concrete as with steel and a selected sample will once more serve to illustrate the types of faults that may be encountered. Honeycombing This is a common construction defect that leaves the surface of the concrete looking like a honeycomb with numerous voids forming between coarse aggregate grains. The cause is inadequate compaction during the forming which allows air to be trapped between the concrete surface and the inside face of the shuttering. This reduces the cover over the reinforcement and leaves voids on the surface that may degenerate more quickly than a firm surface. See Figure 5.4 Issue 1.0 Rev 0 Issue Date 01/09/2006

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Figure 5.4 Honeycombing Efflorescence This is the deposit of salts, usually white, coming out from the concrete mass. It may indicate a reaction between the constituents of the cement and the water used for mixing. Underwater these deposits may well be dissolved Inadequate cover over reinforcement The recommended minimum cover of concrete over reinforcement in very severe conditions, such as surfaces exposed to seawater is 60 mm as stated in CP 110. If the cover is inadequate the reinforcement may corrode which will be manifest by rust stains 5

Stage Three Installation

Concrete structures are commonly built from the base up using a continuous slip forming technique in a dry dock. When the construction reaches a predetermined level the dock is flooded and the structure then floats while work continues. The structure is then towed to position already upright. It is then ballasted down by controlled flooding of tanks built into the base. Stresses are thus minimised and the main consideration with this type of structure is its stability during the tow. This limits the towing speed and weather perimeters that can be tolerated. 6

Stage Four In-Service

The major categories of defects that could cause concern in concrete structures are outlined below. 6.1

In-Service Defect Categories That Affect Concrete Structures

Concrete can deteriorate because of either chemical or physical deterioration. Because concrete is permeable to various ions it is susceptible to chemical attack. Physical damage is possible externally and possibly internally, should the reinforcement corrode, for example it would cause the concrete surrounding it to crack.

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures 6.2

Deterioration Caused By Chemical Attack

It is unlikely that any significant deterioration will occur in concrete of the quality that is normally specified for offshore structures. Never the less, deterioration may occur in concrete that has not been properly compacted or because of environmental pollution. 6.2.1 Sulphate Attack The Tricalcium aluminate, C3A, in the cement can react with magnesium sulphate, which is present in concentrations of about 0.5% in seawater. The reaction is expansive which will lead to cracking but the presence of chlorides inhibits the degree of expansion. The net result is softening and disruption of the concrete in the form of solution and crumbling. Sulphate-resisting Portland cement (SRPC) is a form of Portland cement low in C3A content and the use of this type will minimise the risk of this problem occurring. This type of cement has a higher content of Tetracalcium aluminoferrite, C4AF, than other Portland cements which gives it a darker colour. There are detailed requirements for the use of this cement in CP 110 and BRE Digest 174. The British Standard for this cement is BS 4027:1996 6.2.2 Chlorides Chlorides do not attack plain concrete when present in the concentrations that are normally present in seawater, but they may greatly accelerate the corrosion of the reinforcement by destroying the passivity of the concrete coating. Chloride, [Cl-] ions react with the oxide film on the steel by becoming incorporated into the oxide lattice and increasing the electrical conductivity of the film. The effect of increasing [Cl-] moves the corrosion/passivity boundary to higher pH levels. If carbonation is occurring concurrently this will reduce the pH of the combined water in the concrete, which in turn reduces the concentration of [Cl-] necessary for corrosion to occur. See Figure 5.5

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Figure 5.5 The Concentration of Chloride Ions In Concrete Plotted Against pH 6.2.3 Carbonation Carbon dioxide is present in the air and can attack the concrete directly. It has the effect of destroying the normal passivity of the concrete coating over the reinforcement, thus leading to reinforcement corrosion. The permeation is generally limited to a penetration of approximately 50 mm, which will take many years to accomplish. Figure 5.6 refers

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Figure 5.6 Depth of Carbonation Layer Plotted Against Time CP 110 recommends 60 mm cover over the reinforcement for concrete exposed to very severe conditions. To illustrate the likelihood of carbonation being a problem in the normal course of events it is possible to apply: x = √Dt Hence t = x2/D Where

t = time in years x = depth of penetration D = Diffusivity of CO2 (Taken as 1.4 x 10-13 m2 s-1)

Thus (where x = 60 mm as being the recommended minimum cover) t = (60 x 10-2)2/1.4 x 10-13 x 60 x 60 x 24 x 365 = 815 years In the normal course of events than 815 years would elapse before the steel starts to corrode because of carbonation! While this is not a realistic situation, it does indicate that the effects of carbonation take years to become manifest. Of course potentially any cracks could radically reduce this time by providing a path for the carbonation. It has been found, however that in cracks less than 0.3 mm wide CaCo3 precipitates from the cement and acts as a seal. A further point to note here is that offshore structures are of a prestressed design and are therefore unlikely to crack.

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6.2.4 Reinforcement Corrosion The normal pH of concrete is approximately 12.5 and the pore water incorporated within the concrete at this pH reacts with the steel to form hydrated iron oxide, Fe2O3, which is insoluble at this pH and therefore forms a passive film. The Pourbaix diagram in Figure 5.7 shows the possible environments when considering the electrode potential and the pH surrounding the steel.

Figure 5.7 Pourbaix Diagram for Steel in Concrete If the passivation is destroyed for any reason the reinforcement will corrode. This is an expansive reaction, which leads to cracking and then spalling of the concrete accompanied by rust staining. Once the cracks are wider than 0.3 mm or spalling has occurred seawater will come in contact with the steel and corrosion may proceed more quickly. The first signs of this type of corrosion are rust staining and cracking following the line of the reinforcement.

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures It almost goes without saying that the inter-tidal zone is the area most at risk due to the high oxygen concentration along with the possible increase in chloride ion concentration. By contrast the submerged part of the structure is less at risk mainly because the oxygen content in seawater is low. 6.2.5 Corrosion of Built-in Components This form of deterioration is perhaps more likely than reinforcement corrosion. There are a number of different types of steel components cast into the structure such as riser clamp supports, steel skirts and towing eyes. Should any of this steelwork be in contact with the internal reinforcement the exposed steelwork acts as an active anode and the reinforcement becomes the cathode, as shown in Figure 5.8.

Figure 5.8 Corrosion of Cast-in Items 6.2.6 Cracking It is generally accepted that all concrete structures will contain cracks; indeed this is a design philosophy in reinforced structures. As detailed above these cracks can be caused by: Overloading As in the case on the tensile face of a reinforced beam Shrinkage

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Tuition Notes for 3.1U Course Chapter 5 May be caused at the fabrication stage Thermal Stresses Can be caused at the fabrication stage during the setting period As the presence of cracks in concrete structures will not normally impair the performance and furthermore as the structure is in compression anyway any cracks will be of much less significance than a crack found in a steel structure. As stated above, provided the crack width is less than 3 mm there should be no corrosion to the reinforcement. Never the less all cracks must be reported and there is a standard terminology applied to this class of defect. 7

Standard Terminology

There are a number of standard terms used to precisely describe flaws in concrete. The following list enumerates several of them. General Cracking An incomplete separation into one or more parts Cracks in concrete are further classified by: Direction Longitudinal, transverse, vertical, diagonal or random Width (Fine – less than 1 mm, Medium – 1 to 2 mm, Wide – over 2 mm see Figures 5.9 to 5.10) Depth

Figure 5.9 Medium and Wide Cracks Issue 1.0 Rev 0 Issue Date 01/09/2006

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Figure 5.10 Wide Crack with Rust Staining Pattern Cracking A series of fine interlocking cracks over an area, Caused by either surface shrinkage or expansion of the sub-surface matrix There are a number of other common concrete defects that have not been mentioned earlier but do have standard terms as listed below. Spalling This is the loss of material from the surface of the concrete. It is usually conically shaped and is caused by either an impact or by pressure from within. It may well be associated with reinforcement corrosion in which case it will probably follow the line of the reinforcement and in this case it will not have the typical conical shape, see Figure 5.11

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Figure 5.11 Spalling Delamination This is the loss of a large sheet of surface material that exposes the coarse aggregates. Caused by the build-up of internal pressure over a large area, Figure 5.12

Figure 5.12 Delamination

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Disintegration This involves the general breakdown of the matrix with numerous small fragments breaking away from the surface. This is a very serious problem caused by internal chemical reactions, such as AAR that causes the concrete to become soft. It is a most uncommon problem and there are no instances of it on offshore structures to date Scaling A local or general flaking or peeling away of the surface layer, occasionally there is some loss of aggregate particles. Weathering or chemical reactions between the concrete and the environment may be the cause of this defect. Even if scaling is present it will only become a problem if it becomes very progressive provided there is adequate cover over the reinforcement in the first case. As this defect is associated with poor quality control it should be unlikely to be found on platforms Pop out This appears as small roughly 10 to 50 mm diameter, conically shaped fragments breakaway from the surface. This defect is similar in appearance to spalling but the fragments are smaller. The cause is internal pressure and may be caused by excessive water in the mix. This defect is again unlikely given the QC applied to offshore platforms see Figure 5.13

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Tuition Notes for 3.1U Course Chapter 5 Erosion This is long-term deterioration caused by abrasive action. The abrasive particles may be air or water-born and it may become evident on platforms in the inter-tidal region later in the life of the structure. This is a long-term problem most unlikely to cause any concern until several years have passed Stains The most serious stain on concrete surfaces is rust staining. This may be the early sign of reinforcement corrosion and therefore all such stains must be reported. It is possible that subsequent investigation and document checks will show stains to be benign as there are a number of causes that are of no structural significance o Reinforcement may have been included to withstand construction stresses and subsequently is un-important o Mesh reinforcement that is not structurally significant could possibly corrode and would then look cosmetically poor but once again be of no real significance In any case the rule is to report and allow the responsible engineers make the judgement. See Figure 5.11. In Artic waters freeze/thaw damage is quite possible. The repeated freezing and thawing of moisture in the porous concrete surface in the splash zone causes high stresses in these pores due to water expansion during freezing. This in turn causes small fissures which then fill with water on the next annual cycle and so on Marine organisms that bore into the concrete have seriously attacked concrete structures in tropical water. The organisms involved seem to have an affinity for limestone and include: o Boring worms o Mussels and o Sponges The boring sponge Cliona and the boring mussel Lithophaga are both known to do considerable damage. The sponge confining its activities to the outer surfaces and the mussel penetrates deeply into the interior where it fashions ovoid cavities o Probably the most destructive mussel is the species Lithophaga antillarum that can grow up to 10 cm in length and 2 cm in diameter. This species is common in tropical waters world wide There are several other marine organisms that also bore into concrete such as: Gastrochaena, which is a bi-valve mollusc Upogebial which is a burrowing mud shrimp There are also other creatures that make their homes in concrete.

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures This problem has been known for a number of years in the Persian Gulf and the current method of dealing with it is to fit a cladding to the concrete surface to try to prevent access to the marine organisms in the first place thus preventing the problem. As a resume Table 5.14 is laid out to summarise the in-service types of defects mentioned so far in this chapter.

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Defect Type

Reported As

Description

Cause

Details Reported

General Cracking

Cracking

Jagged separations with or without a gap

Overloading, steelwork corrosion or shrinkage

Length, depth and width

Pattern Cracking

Cracking

As above but covering an area

Volume changes between interior and exterior

Surface area, width and depth

Exudation

Surface deposit

Viscous, gel-like substance; often associated with cracking

Alkali Aggregate Reaction (AAR)

Severity, area and thickness

Rust Stains

Surface deposit

Brown stains

Corrosion of surface steelwork, tie wires or reinforcement

Severity, area and thickness

Incrustation

Surface deposit

White, crusty deposit

Leaching of lime from cement

Severity, area thickness

Popout

Concrete loss

Shallow conical depression

Increase in internal pressure

Area and depth

Spalling

Concrete loss

Conical shaped fragment expressed from the surface

External impact or internal pressure

Area and depth

Delamination

Concrete loss

Loss of a large area of the concrete surface

Internal pressure

Area and depth

Voids between coarse aggregate particles

Lack of vibration

Area and depth

Honeycombing Construction defect

Table 5.14 Possible In-service Defects in Concrete 8

Additional In-service Defects

The Offshore Technology Report OTH 84 206 was produced in 1984 and currently remains the most comprehensive document for classification of defects on offshore structures. Apart from the defects already mentioned there are a number that are defined in this publication an extract of which, showing

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures photographs of the anomalies is listed in the appendix to this chapter Appendix 1. The document groups defects into 3 categories: Category A (Defects) Category B (Areas of Concern) Category C (Blemishes)

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Tuition Notes for 3.1U Course Chapter 5 Bibliography A Handbook for Underwater Inspectors L K Porter HMSO Underwater Inspection M Bayliss, D Short, M Bax E & F N Spon Materials The Open University

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Tuition Notes for 3.1U Course Deterioration of Offshore Concrete Structures Notes:

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Tuition Notes for 3.1U Course Chapter 6

CHAPTER 6 Marine Growth 1

Introduction

Once any structure is placed into the sea marine growth will colonise it. This build-up will have two effects: First The profile area of any component presented to the water flow will be increased. This will increase the force on the structure overall. Second Marine growth will change the texture of the surface from a smooth, round steel or painted surface, to a surface made much rougher by the presence of the marine growth on it. This roughness will increase with time as the surface becomes more irregular due to parts of the dead marine growth sloughing off. The effect or this is to increase the drag coefficient. Both these effects increase the force on the structure. Information on the types and amounts of marine growth build-up is required to confirm or modify the design-predicted loads on the structure. See Figure 6.1.

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Tuition Notes for 3.1U Course Marine Growth These two effects of marine growth will have a knock-on effect with the structure that will manifest itself By producing an increase in mass without any significant change in stiffness. This causes a reduction in the structure’s natural frequency By increasing the added mass of water and the drag forces on the structure. Marine growth being most abundant at and just below the water level coincides with the zone of maximum wave and water force. So the forces on the structure are increased in the region of maximum water force By affecting the corrosion rate, either by accelerating or retarding it By reducing the effective area of the service inlets and outlets, hence reducing system efficiency By obscuring the important features on the structure, such as diver orientation marks, valve handles anodes and similar objects By making inspection impossible before cleaning These effects give marine growth such an importance that it is necessary to examine the problem in a little more detail. 2

Types of Marine Growth

From the engineering standpoint there are two main categories of fouling; soft and hard. Those organisms that have a density approximately the same as seawater cause soft fouling. They are important because of their bulk, but are generally easy to remove Organisms causing hard fouling are much denser and more firmly attached to the structure and therefore are more difficult to remove These organisms will colonise the structure at different rates and at different depths dependant on the natural propensity of the particular species. Some guidance is available to designers as indicated in Table 6.2. Using this and other data designers can predict the most propitious time of the year to launch and install a structure.

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Tuition Notes for 3.1U Course Chapter 6

Type

Settlement Season

Typical Growth Rate

Typical Coverage (%)

Typical Terminal Thickness

Depth (Relative To MSL)

Comments

Hard Fouling Mussels

Jul – Oct

25 mm in1 yr

100

150 –200 mm

0 to –30 m

But faster growth rates are found on installations in the North Sea

50 to 70

About 10 mm (tubeworms lay flat on the steel surface)

0 to mud line

Coverage is often 100% especially on new structures 1 to 2 years after installation. Tubeworms also remain as a hard, background layer when dead

0 to mud line

A permanent hydroid ‘turf’ may cover an installation and obscure the surface for many years

50 mm in 3 yr 75 mm in 7 yr Solitary tubeworms

May – Aug

30 mm (L) in 3 mths

Soft Fouling Hydroids

Apr – Oct

50 mm in 3 mths

100

Summer 30 – 70 mm Winter 20 – 30 mm

Plumose

Jun – Jul

50 mm in 1 yr

100

300 mm

-30 to –120 m

Usually settle 4 to 5 years after installation and can then cover surface very rapidly. Live for up to 50 years

Soft coral

Jan – Mar

50 mm in 1 yr

100

About 200 mm

-30 to –120 m

Often found in association with anemones

-3 to –15 m

May be several years before colonisation begins but tenacious holdfast when established. Present on some installation in Northern and Central North Sea

Seaweed Fouling Kelp

Feb – Apr

2 m in 3 yrs

60 to 80

Variable up to 6 m long

Table 6.2 Typical Distribution of Marine Growth in The North Sea (Extract from “Offshore Installations: Guidance on design, construction and certification” Forth edition – 1990)

2.1

Soft Fouling

Organisms in this group include: Algae This is often referred to as slime and is generally the first organism to inhabit an offshore structure. As it is very light sensitive, it is seldom observed in any quantity below 20 m (76 feet). This is a very large family of organisms and even includes kelp, thus is goes from the very small to the very large. Bacteria This, like algae, will be amongst the first inhabitants of an offshore structure and will be present in depths will in excess of 1000m (3333 feet)

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Tuition Notes for 3.1U Course Marine Growth Sponges These are often found as a fouling species on offshore platforms and are present at depths greater that 1000m (3333 feet)

Figure 6.3 Different Species of Sponges Sea Squirts These are soft-bodied animals and sometimes grow in large colonies

Figure 6.4 Different Species of Sea Squirts Hydroids These grow in colonies and from their appearance can be mistaken for seaweed, but they are in fact animals related to sea anemone. The colonies can produce dense coverage to depths of 1000m (3333 feet)

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Tuition Notes for 3.1U Course Chapter 6

Figure 6.5 Close Up Photograph of a Hydroid

Figure 6.6 Different Species of Hydroids Seaweeds There are many types of seaweed that attach themselves to underwater structures, but of these, kelp produces the longest fronds, which in the North Sea, grow up to 6m (20 feet) in length under favourable conditions

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Figure 6.7 Green Seaweed (Left) Bladder Wrack (Ascophyllum) (Right)

Figure 6.8 Kelp Holdfast (Centre) Laminaria Digitalis (Left) Laminaria (Right)Bryozoa This has a moss-like appearance, and is really an animal with tentacles

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Figure 6.9 Different Species of Bryozoa Anemones These are sometimes called anthozoans, which means ‘flowering animals’. The cylindrical body is surmounted by a radical pattern of tentacles and looks a bit like broccoli. It attaches itself to the structure by a basal disc, and this attachment is so firm that attempts to remove it often result in tearing the body of the anemone. The colours and shapes are extremely variable even within the same species

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Tuition Notes for 3.1U Course Marine Growth

Figure 6.10 Anemones Dead Men’s Fingers (Alcyonium Digitalum) Colonies have been observed on pier piles, rocks on the foreshore and offshore structures. These colonies often grow to 150 mm (6 inches) in length. When submerged, many small polyps arise from the finger-shaped, fleshy main body, each polyp having eight feathery tentacles. It is white to yellow or pink to orange in colour, but when out of the water it is flesh coloured and the similarity to the human hand gives it its common name

Figure 6.11 Dead Men’s Fingers 2.2

Hard Fouling

Composed of calcareous or shelled organisms, the common types in this group include: -

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Tuition Notes for 3.1U Course Chapter 6 Barnacles The common species is Balanus Balanoides. These grow in dense colonies to a depth of 15 – 20m (49 – 67 feet), but are observed to depths of 120m (394 feet)

Figure 6.12 Barnacles Mussels The main species is Mytilus edulis. The hard-shelled mollusc attaches itself to the structure by byssal threads at the hinge of the shell. These thread attachments are very strong and mussels generally form dense colonies. Main colonisation is to depths of 20m (67 feet), but mussels are found to depths of about 50m (164 feet)

Figure 6.13 Blue Mussels (Mytilus edulis) Tubeworms The full title for this species is calcareous serpulid tubeworm. This often forms on flat surfaces. It is white in colour, very firmly attached to the surface Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Marine Growth of the metal and difficult to remove. It also grows in colonies and these have been known to fill a warm water outlet, arranging themselves parallel to the flow to obtain maximum nutriments. Power cleaning is required to remove this growth, so firmly is it attached. Although the main growth occurs to depths of 50m (164 feet), tubeworms are found to depths of 100m (328 feet)

Figure 6.14 Tubeworm 3

Factors Affecting the Rate of Marine Growth

If no steps are taken to prevent growth, such as application of an anti-fouling solution or paint, the formation of bacterial slime occurs in two to three weeks. As indicated in Table 6.3 marine growth can mature very rapidly with barnacles and soft fouling having been known to attach themselves and reach maturity on three to six months. It generally takes two seasons for mussel colonies to develop, often on top of the dead earlier fouling. The type of organism, its development and growth rate will depend on several factors, including the following. 3.1

Depth

Figure 6.15 gives a generally accepted diagrammatic representation of the combined effects of weight and volume on the various types of marine fouling in British waters. This should be read in conjunction with Table 6.2, which contains information more specific to the design function. The diagram shows clearly that the most weight is added in the vicinity of the surface which is the region of highest water-induced loading The total column in the diagram is not the sum of the others, but an estimate of a balanced colony. Note that the long lengths of seaweed have not been included. Increase in depth reduces light intensity, which therefore reduces the ability of organisms such as algae to photosynthesise. Algae therefore gradually disappear with depth and there is also a change in species to red algae at the greater depths. Algae growth at depths below 30m (98 feet) has been observed in the North Sea due mainly to the clarity of the water.

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Tuition Notes for 3.1U Course Chapter 6

Figure 6.15 Diagrammatic representation Of the Distribution of Marine Growth with Depth 3.2

Temperature

In general, a rise in water temperature will increase the growth rate of a colony. The growth rate approximately doubles with a 10o C rise in temperature. There will of course be a limit and most organisms cease growth at 30o – 35o C. As the temperature variation is greatest near the surface, there is seasonal growth in the marine colonies near the surface, and continuous, slower growth as the depth increases. 3.3

Water Current

The speed at which the water flows over the surface plays an important part in the type of fouling colony that develops. There are two aspects to consider, the first being that of the larvae attaching themselves to the structure. It is suggested that at speeds greater than 1 knot, many larvae are unable to attach themselves. However, once attached, most fouling can withstand water currents of more than 6 knots. At high water velocities, weakly attached fouling is removed leaving only the firmly attached hard fouling. Also, colonies growing on dead or dying fouling become loose Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Marine Growth and may be sloughed off. The larvae can attach themselves to structures during slack flow periods, on in localised spots of slower flow or dead water, such as crevices and locations between hard fouling The second aspect to consider is that in general, once the organism is established, a strong current brings more food and growth is accelerated 3.4

Salinity

In nearly fresh water, fouling is usually confined to algae slime. As the salinity increases, so the amount and type of fouling increases. First hydroids and barnacles and finally mussels occur. The normal salinity of seawater is about 3% - 3.5% and the size of mussels, for example, increases five-fold from a salinity of 0.6% to 3.5%. 3.5

Food Supply

Growth of the fouling is obviously dependent on the quantity of nutriment available. Growth rates seem to be faster in coastal waters then those a few miles offshore where the water is deeper. Investigations suggest that the slow currents that circulate around platforms become enriched with nutriments from sewage and other waste that will increase the growth rate. 3.6

Cathodic Protection

There are two types of corrosion protection widely used on North Sea structures (see Chapter 10) on those that use sacrificial anodes, the patterns of marine growth on the structures themselves seem normal, but the anodes generally remain clear of growth. The other system, which uses an impressed current to cancel the corrosion-induced ionic currents between the structure and the sea, suggests, on a limited amount of evidence, that the marine growth rate is increased. Currently the mechanism that encourages an increased growth rate in not understood, more data is required before the observations of increased growth can be confirmed.

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Tuition Notes for 3.1U Course Chapter 6

Bibliography Underwater Inspection Mel Bayliss David Short Mary Bax E & F N Spon ISBN 0-419-13540-5 A Handbook for Underwater Inspectors L K Porter HMSO OTI 88 539 Structural Materials The Open University Butterworth’s ISBN 0408 04658 9

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Tuition Notes for 3.1U Course Chapter 7

CHAPTER 7 Corrosion 1

Energy Considerations in Corrosion

With time most materials react with their environment to change their structure. The reaction in metals is called corrosion, in polymers (plastics) degradation and in concrete weathering. Corrosion in metals is defined as the chemical or electrochemical reaction between a metal and its environment, which leads to one of three consequences: The removal of the metal The formation of an oxide The formation of another chemical compound This change in the metal will be expected if the thermodynamics (energy state) of the system is considered. The FIRST LAW OF THERMODYNAMICS states: Energy can neither be created nor destroyed As a direct consequence of this Law when spontaneous changes occur they must follow a rule, which is: Whenever a spontaneous change occurs it must release free energy from the system to the surrounding at constant temperature and pressure Which is a way of stating the SECOND LAW OF THERMODYNAMICS when corrosion occurs naturally it releases free energy, as it is a spontaneous process. Take the case of a metal such as iron or aluminium as an example; both are fund in nature as ores which, when analysed, are found to be a chemical compound including oxygen and carbon amongst other elements. This necessitates the extraction of the metal itself from the other elements before it can be used in fabrication. The process whereby the metal is extracted requires either the smelting of the ore or an electrolysis process. The final metal produced is therefore at a higher energy level than the ore from which it was extracted i.e. energy is added to the system. One of the fundamental laws of equilibrium is that all systems try to reduce their energy level to a minimum. This is why water runs downhill thus reducing its potential energy level as it flows. In similar fashion metals tend to reduce their energy and therefore the rule imposed by the second Law. Thus free energy is released. There are numerous forms of energy but the energy causing corrosion is chemical energy that is utilised to form lower energy chemical compounds, like the metal oxide, which resemble the original ore. Because steel (iron alloys of Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Corrosion various types) is such an important material in building and industry the corrosion of iron has a special term, rust. Figure 7.1 refers.

Figure 7.1 Changes in Energy Levels of a Typical Metal Extracted From Ore 2

The Corrosion Process

Knowing there is a driving force for the process it is necessary to consider the mechanism by which corrosion can take place. Firstly a reminder of the basic structure of the atom will assist in the understanding to the topic. In its simplest form an atom is a positive nucleus surrounded by negatively charged electrons. Figure 7.2 shows a simplified diagram of the structure of an atom that is adequate for the purposes of this discussion.

Figure 7.2 Simple Structure of an Atom The overall charge on the atom is zero and an atom is so composed that the negative charge of the electrons is equal to the positive charge of the nucleus.

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Tuition Notes for 3.1U Course Chapter 7 However, electrons can be added to or taken from the group that surrounds each atom. When this happens, the overall charge on the atom is no longer zero. This condition of the atom is called ‘ionic’. Thus if the atom loses an electron it becomes a positive ion, which means that the atom now has a positive charge. This may be referred to as a cation. If the atom gains an electron it becomes a negative ion and now has a negative charge. This may be referred to as an anion. The first step in the corrosion process is that metal atoms change their state from being metallic (that is no charge on the atom) to being ionic (that is having a charge on the atom) by losing at least one electron from the outer shell. The process of corrosion then goes on at the atomic level, each atom losing one or more (usually no more than 3) electrons to become an ion. 2.1

The Anodic Reaction

The reaction in which the metal is changed from its metallic state into its ionic state is known as an anodic reaction that is part of an overall reaction involving the metal and other species present in the environment. This process is also called oxidation. The overall reaction may be summarised by a chemical equation thus: M

Mz+ + ze-

Z may be 1, 2 or 3. Higher values are possible but rare. Reaction such as those indicated by this equation that produce electrons are known as oxidation Figure 7.3 illustrates this anodic reaction diagrammatically.

Figure 7.3 Anodic Reaction The site at which it takes place is the anode, which is positive using conventional notation. The anodic reaction for iron releases two electrons. This Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Corrosion is shown diagrammatically in Figure 7.4, which represents a free rusting iron surface immersed in seawater.

Figure 7.4 Anodic Sites on Surface of Iron Exposed To Seawater This is one part of the reaction in electrochemical corrosion that takes place in the presence of an electrolyte that is often water or a water-based solution of ionic compounds such as acids, bases or salts. The metal ion passes into solution and the electron passes through the metal that is not actually being corroded, that is, an electric current flows as indicated in Figure 7.4 2.2

The Cathodic Reaction

These ‘free’ electrons formed in the anode reaction must be ‘used up’ if the reaction is to proceed. This part of the reaction in the electrochemical corrosion process therefore takes place at the site where the free electrons are neutralised and is known as the cathodic reaction. Alternatively reactions such as this that consume electrons are also known as reduction reactions. A part reaction is illustrated in Figure 7.5

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Tuition Notes for 3.1U Course Chapter 7

Figure 7.5 Cathodic Reaction Typically a complete reaction is for the free electrons to be taken up by positive ions and atoms of oxygen in the electrolyte. This gives the oxygen a negative charge. Oxygen, however, readily accepts the free electrons because for its electron stability it needs eight electrons in its outer valence shell yet occurs naturally with only 6. Figure 7.6 refers.

Figure 7.6 Cathode Reaction

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Tuition Notes for 3.1U Course Corrosion Free electrons move through the metal cathode to its surface where negative ions form and subsequently emit free electrons into the electrolyte where they combine with elements creating different compounds. The site of this reaction is known as the cathode, which conventionally is negative. The actual reduction reaction at the cathode will vary according to the composition of the electrolyte. Some common frequent recurring reactions in metallic corrosion are: 2H+ + 2e

Hydrogen evolution

H2

+

Oxygen reduction (acid solutions)

O2 + 4H + 4e

2H2O

Oxygen reduction (neutral or basic solutions)

O2 + 2H2O + 4e

4OH-

Metal ion reduction

M3+ + e

M2+

Hydrogen evolution is a common reaction when the electrolyte is acidic while oxygen reduction is very common since any aqueous solution in contact with air is capable of producing this reaction. It is, of course, the reaction encountered in seawater. Metal ion reduction is less common and is normally found in chemical process streams. The common denominator with all these reactions is that they consume electrons and this is the most important point to note. 2.3

Seawater Corrosion

These partial reactions are included here because they can be used to interpret virtually all corrosion problems. For example, consider iron in seawater; corrosion occurs. The anodic reaction is:

Fe2+ + 2e

Fe

The seawater contains dissolved oxygen and therefore: The cathodic reaction is:

O2 + 2H2O + 4e

4OH-

The effective overall reaction can be found by adding these two equations thus: 2Fe + 2H2O + O2

2Fe2+ + 4OH-

2Fe(OH)2

This is ferrous hydroxide precipitate from solution. This compound is unstable in oxygenated solutions and it oxidises to ferric salt: 2Fe(OH)2 + H2O + ½ O2

2Fe(OH)3

This final product is the familiar rust. 2.4

Electrochemical Aspects of Corrosion

A fundamental definition for corrosion is: CORROSION IS THE DEGRADATION OF A METAL BY AN ELECTROCHEMICAL REACTION WITH ITS ENVIRONMENT For corrosion to take place four criterions must apply: There must be an anode. This normally corrodes by loss of electrons There must be a cathode. This does not normally corrode Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 7 There must be an electrolyte. This is the name given to the solution that conducts electricity. Pure distilled water is not an electrolyte while seawater is There must be an electrical connection between the anode and the cathode These four elements are shown diagrammatically in Figure 7.7 and all electrochemical corrosion takes place by setting up cells like this.

Figure 7.7 Corrosion Circuit As this is an electrochemical reaction and the chemistry has been touched on already a few basic electrical definitions will round off this section. 3

Electrical Theory

Electricity is the passage of electrons between two defined points. This normally occurs through a metal wire connecting the two points and is called a current. Electricity can also pass through suitable aqueous solutions, but the electrical charge is then carried by ions. The amount of charge carried by an electron is known and when a given electron flow is passed at a constant rate it is measured in amperes and is given the symbol I. o In the MKS system one ampere is defined as that constant current which, if maintained in each of two infinitely long straight parallel wires of negligible cross-section placed 1 m apart, in a vacuum, will produce between the wires a force of 2 x 10-7 Newtons per m length The driving force causing this current to flow is the potential difference between two points and is measured in volts, which has the symbol V.

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Tuition Notes for 3.1U Course Corrosion o In the MKS system this is defined as that difference of electrical potential between two points of a wire carrying a constant current of 1 ampere when the power dissipation between those points is 1 watt The flow of electric charges is impeded by a quantity called resistance and between any two points there is always some resistance to the passage of the current. The unit of resistance is the ohm which has the symbol Ω. o The MKS system defines the unit of electrical resistance as being the resistance between two points of a conductor when a constant potential difference of 1 V applied between these points produces in the conductor a current of 1 A During the majority of this chapter all discussion and illustrations will be in terms of electron or ion flow and as far as possible positive and negative notations will be avoided so as to avoid confusion, which often occurs when corrosion is studied. This confusion arises because of an historical accident that resulted in producing what is now called conventional current. Electron flow is exactly opposite to conventional current, which is what causes the confusion when studies in corrosion so often involve discussion on electron or ion flow. To avoid such problems for the rest of this discussion on corrosion only electron flow will be considered. Figure 7.8 illustrates the two types of flow.

Figure 7.8 Conventional and Electron Flow

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Tuition Notes for 3.1U Course Chapter 7 Bibliography A Handbook for Underwater Inspectors L K Porter HMSO Underwater Inspection M Bayliss, D Short, M Bax E & F N Spon Corrosion for Students of Science and Engineering K R Trethewey & J Chamberlain Longman Scientific & Technical

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Tuition Notes for 3.1U Course Chapter 8

CHAPTER 8 Types of Corrosion 1

Corrosion Cells

Corrosion cells, using the corrosion process outlined in Chapter 7, can be set up by many different means, but they all operate because there is some dissimilarity between the anode and the cathode, such as: Dissimilar metals Dissimilar phases in the grains of the metal Dissimilar energy levels between the grain and the grain boundary of the metal Dissimilar ion concentrations Dissimilar oxygen concentrations 1.1

Dissimilar Metal Corrosion Cell

It is found that when dissimilar metals are placed in the same fluid (electrolyte) a potential difference (voltage) exists between them. This can be demonstrated easily by placing two rods of different metals in water and connecting a voltmeter between them. The voltmeter measures a voltage and current flows from the anode to the cathode via the outside connection. The cell acts as a very basic, low powered battery and in battery terms the anode is the negative and the cathode the positive. Electrons flow from the negative terminal to the positive terminal in the external circuit. Figure 7.7 refers. It is possible to determine which of the two metals will be the cathode and which the anode by reference to an Electrochemical Force Series. 1.1.1 The Electrochemical Force Series Under standard conditions, where the electrolyte is dilute sulphuric acid at a temperature of 25oC, the potential of various metals is measured and given in a table known as the Electrochemical Force Series, or Electromotive Series, (see Table 8.1). From the table, it will be seen that any metal will be anodic to any metal lower in the table and cathodic to any metal higher in the series. It must be remembered, however, that the table only applies under the standard conditions stated.

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Tuition Notes for 3.1U Course Types of Corrosion

Metal Atom Potassium Calcium Sodium Magnesium

Electrode Reaction Atom to Ion K Ca Na Mg

Potential in Volts Standard

K+ + e++

-2.92 -

Ca

+ 2e

+

-2.87

-

Na + e

-2.71

Mg++ + 2e++

-

-2.34

Beryllium

Be

Be

+ 2e

-1.70

Aluminium

Al

Al+++ + 3e-

-1.67

Manganese

Mn

++

Mn

++

+2e

-

-1.05

-

-0.76

Zinc

Zn

Zn

+ 2e

Chromium

Cr

Cr+++ + 3e+++

-0.71

-

Gallium

Ga

Ga

+ 3e

-0.52

Iron

Fe

Fe++ + 2e-

-0.44

Cadmium Indium Thallium

Cd In

++

-

+ 2e

-0.40

+++

-

-0.34

Cd In

Ti

+ 3e

Ti+ + e++

-0.34 -

Cobalt

Co

Co

+ 2e

-0.28

Nickel

Ni

Ni++ + 2e-

-0.25

Tin

Sn

++

Sn

++

-

-0.14

-

-0.13 0.00

+ 2e

Lead

Pb

Pb

Hydrogen

H2

2H+ + 2e-

Copper Copper Mercury Silver Palladium

Cu Cu 2Hg Ag Pd

++

Cu

+ 2e

-

+ 2e

Cu+ + eHg2

++ +

0.52 -

+ 2e

Ag + e

0.80

Pd++ + 2e++

Hg

Platinum

Pt

Pt++ + 2e-

Gold

Au

+++

Au

+

0.83

-

Hg

Au

0.80

-

Mercury

Gold

0.34

+ 2e

0.85 Ca 1.2

-

+ 3e

Ca 1.42

-

Au + e

1.68

Table 8.1 Electrochemical Force Series Similar tables are produced for metals under actual conditions and these are called Galvanic Series. Table 8.2 give the series for seawater. The same rule applies to the Galvanic Series as for the foregoing table, i.e. metals found lower in the series are cathodic to any metal above them. For example, zinc is higher Issue 1.0 Rev 0 Issued 01/09/2006

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Tuition Notes for 3.1U Course Chapter 8 in the series than mild steel; therefore, if zinc is connected to mild steel and immersed in seawater zinc will be the anode and corrode and mild steel will be the cathode and not corrode. If on the other hand mild steel, in the form of a ship’s hull is connected to manganese bronze, the ship’s propeller, the mild steel now becomes the anode and corrodes and the manganese bronze propeller is the cathode, which does not corrode. Magnesium Magnesium Alloys Zinc Galvanised Iron Aluminium 52Sh Alcad Cadmium Mild Steel Wrought Iron Cast Iron 50-50 Lead-Tin Solder 18-8 Stainless (Active) Lead Manganese Bronze Nickel (Active) Yellow Brass Admiralty Brass Aluminium Bronze Red Brass Copper Nickel (Passive) 70% Ni, 30% Cu (Monel) 18-8 (3%Mo) Stainless steel (Passive) Silver Gold

Table 8.2 Galvanic Series in Seawater

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Tuition Notes for 3.1U Course Types of Corrosion This type of corrosion cell, consisting of two dissimilar metals, is easy to identify, but corrosion can occur in a much more localised way, caused by small-size effects that can lead to corrosion pits and thereby cause considerable damage. This type of corrosion and some others are discussed below. 1.2

Concentration Cell Corrosion

Corrosion of this type is associated with crevices in the order of 25 to 100 µm wide and commonly involves chloride ions in the electrolyte. The stages in the process are: Corrosion will at first occur over the entire surface of the exposed metal at a slow rate, both inside and outside the crevice. During this period of time the electrolyte may be assumed to have a uniform composition and normal anodic and cathodic processes take place. Under these conditions positive metal ions and negative hydroxyl ions are produced so as to maintain equilibrium within the electrolyte This process consumes the dissolved oxygen, which results in the diffusion of more oxygen from the atmosphere at any surface where the electrolyte is in contact with air. In turn then the oxygen in the bulk of the electrolyte is replaced more easily at metal surfaces rather than in any small crevices. This creates a low oxygen situation within the crevice that in turn impedes the cathodic process and the production of hydroxyl ions is therefore reduced This results in excess positive ions accumulating in the crevice which causes negative ions to diffuse there from the bulk of the electrolyte outside in order to maintain minimum potential energy overall. The metal ions, water molecules and chloride all react in complicated chemical reactions forming complex ions, which it is thought, react with water in an hydrolysis reaction resulting in corrosion products. This can be described by a simplified equation thus M+ + H2O

MOH + H+

The increase of hydrogen ion concentration accelerates the metal dissolution process, which, in turn, makes the problem worse, as does the accompanying increase of anion (chloride) concentration within the crevice. An important feature of active crevice corrosion cells is that they are autocatalytic that is once started they are self-sustaining. It is worth underlining the fact that the electrolyte in an active crevice can become very acidic. This is the situation shown in Figure 8.3. The metal inside the crevice is corroding rapidly while that outside is cathodically protected.

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Tuition Notes for 3.1U Course Chapter 8

Figure 8.3 Crevice Corrosion 1.3

Pitting

Pitting is localised corrosion that selectively attacks areas of a metal surface. The point of initiation may be: A compositional heterogeneity such as an inclusion or segregate or precipitate A surface scratch or any similar blemish in an otherwise perfect film Or it may be an emerging dislocation or a slip step caused by applied or residual tensile stresses. o All metals have crystal lattice structures but these are never defect free. All metals contain imperfections in their lattice structures, and these are known as defects, these may occur in a number of ways: Vacancies This is where there is an atom missing from the lattice site Substitutional Defects This is where a foreign atom occupies a lattice site that would have been occupied by a host atom Interstitial Defects This is where an atom occupies a site that is not a normal lattice site and it is squeezed in

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Tuition Notes for 3.1U Course Types of Corrosion between atoms of the host lattice. The interstitial atom may be either a host atom or a foreign atom. Figure 8.4 refers

Figure 8.4 Point Defects in a Crystal Lattice These point defects are very significant in the theory of alloying where they cause a significant improvement in mechanical properties of metals. They also play a role in some corrosion mechanisms, notably hydrogen embrittlement, selective attack, oxidation and hot corrosion, that all rely on the diffusion of species through the metal lattice Another type of defect occurs within the grain structure when planes of atoms are not perfectly fitted into the lattice. These are known as line defects. An example of this type of defect is the dislocation and a specific examples of this type of dislocation are: o Edge Dislocations This is where an ‘unfinished’ plane of atoms is present between two other planes. Figure 8.5a refers o Screw Dislocations This is where a plane is skewed to give it a different alignment to its immediate neighbour. Figure 8.5b refers

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Tuition Notes for 3.1U Course Chapter 8

Figure 8.5 (a) Edge Dislocation (b) Screw Dislocation Corrosion pits once formed propagate in the same way as crevice corrosion; it is the initiation phase that is different. In the case of corrosion pits the initiation is dependant on metallurgical factors alone. Now consider the case of a water drop laying on the surface of a sheet of clean mild steel o The corrosion process initiates uniformly on the surface of the steel under the water. This consumes oxygen by the normal cathode reaction in what is a neutral solution at this stage o This causes an oxygen gradient to form within the water drop. It is obvious that the wetted area around the water/air interface has more oxygen diffusion from the air than the centre of the drop o This concentration gradient anodically polarises the central region, which dissolves o The hydroxyl ions generated in the centre of the drop at the cathode diffuse inwards and react with iron ions diffusing outwards, causing the deposition of insoluble corrosion product around the depression, or pit

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Tuition Notes for 3.1U Course Types of Corrosion o This further retards the diffusion of oxygen, accelerates the anodic process in the centre of the drop and causes the reaction to be autocatalytic. Figure 8.6 refers

Figure 8.6 The Mechanism of Pitting Because Of Differential-aeration Beneath a Water Drop As the process continues the corrosion products accumulate over the pit and its immediate surroundings, forming a scab or tubercle and isolating the environment within the pit from the bulk electrolyte. It is thought that the autocatalytic process is assisted by an increased concentration of chloride ions within the pit. This type of corrosion would be possible in the splash zone of a structure if it were not protected with a coating such as paint 1.4

Inter-granular Corrosion

Intergranular corrosion occurs between the grain boundaries because of precipitates in these regions. This is primarily because grain boundaries are the preferred sites for the precipitation and segregation processes which occur in many alloys. These intrusions are of two types: -

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Tuition Notes for 3.1U Course Chapter 8 Intermetallic (Iintermediate Constituents) These are species formed from metal atoms and having identifiable chemical formulae. They can be either anodic or cathodic to the metal Compounds These are formed between metals and non-metallic elements, such as; hydrogen, carbon, silicon, nitrogen and oxygen o Iron carbide and manganese sulphide, which are both important constituents of steel, are both cathodic to ferrite In principle any metal that has intermetallics or compounds at grain boundaries will be susceptible to Intergranular corrosion. For example, it has most frequently been found in austenitic stainless steels but it may occur in ferric and two-phase stainless steels and nickel base corrosion resistant alloys. Plain carbon steel is a two phase metal and some grains are cathodic while others are anodic and Intergranular corrosion initiates as indicated in Figure 8.7

Figure 8.7 Corrosion in Two Phase Metal In the Galvanic Series the α phase is below the β phase and will therefore corrode 1.5

Grain Boundary Corrosion

The driving force behind grain boundary corrosion is the area of higher energy found at the grain boundary itself. These higher energy regions become the anodic sites while the bulk of the grain itself becomes the cathode. This situation results in the loss of material in the anodic reaction at the grain boundaries themselves in the form of a line.

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Tuition Notes for 3.1U Course Types of Corrosion

Figure 8.8 Grain Boundary Corrosion Weld decay or preferential corrosion is an example of this type of decay. In this case the boundary is the fusion boundary that forms along the toe of the weld and is a region of higher energy. This region becomes the anode and corrosion sets in, often giving quite significant visual indications of its presence. Figure 8.9 refers

Figure 8.9 Weld Decay or Preferential Corrosion 1.6

Stress Corrosion Cracking

This type of corrosion is a form of Intergranular corrosion that increases in severity when the material is subjected to a tensile load and a specific environment. The effects are to concentrate the corrosion on a limited number of grain boundaries that are at right angles to the direction of loading.

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Tuition Notes for 3.1U Course Chapter 8 A common feature of stress corrosion cracking that repeatedly occurs is the unexpectedness of its manifestation. Often a material that has been chosen for its corrosion resistance is found to fail at a stress level well below its normal fracture stress. It is rare that there is any obvious evidence of failure and it presents itself in components that are apparently unstressed. Problems with pipes and tubes are common because of the hoop residual stresses that are the result of the fabrication process. Stress-relieving heat treatments are a vital part of the quality control for these components because of this. It is currently agreed that there is no one mechanism for producing stress corrosion cracking, but rather a number of significant factors. For this cracking to occur there must be tensile stress, which may be applied directly during the working life of the structure, or it may be present as a consequence of the installation or fabrication process In general alloys are more susceptible than pure metals although copper is one known exception A particular metal may crack in the presence of a relatively few chemical species that may be present in small concentrations In the absence of stress the alloy is usually inert to the same environment that would otherwise cause cracking Even with particularly ductile materials stress corrosion cracks have the appearance of a brittle fracture It is usually possible to determine a threshold stress below which stress corrosion cracking does not occur. 1.7

Fretting Corrosion

Fretting describes corrosion occurring at contact areas between materials under load subjected to vibration and slip. In appearance it shows pits and groves in the metal surrounded by corrosion products. It has been observed in a number of different components in machinery and in bolted parts. In essence this is a form of erosion corrosion that occurs in the atmosphere rather than under aqueous conditions. Fretting corrosion is very detrimental due to the destruction of metallic components and the production of oxide debris. This leads to loss of tolerance and may result in fatigue fracture due to the excessive strain caused by the extra movement and the pits acting as stress raisers. A classic case on land of fretting occurs at bolted tie plates on railroad tracks. The basic requirements for the occurrence of fretting corrosion are: The interface must be under load Vibration or repeated relative motion between the interface must be sufficient to produce slip or deformation on the surfaces

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Tuition Notes for 3.1U Course Types of Corrosion The load and relative motion of the interface must be sufficient to produce slip or deformation on the surfaces The relative motion need only be as little as 10-10 m but it must be cyclic in nature and does not occur between surfaces in continuous motion. There are two theories proposed for fretting corrosion; wear-oxidation and oxidation-wear both of which are shown schematically in Figures 8.10 and 8.11

Figure 8.10 Schematic Illustration of the Wear-oxidation Theory of Fretting Corrosion The wear-oxidation mechanism is based on the concept that cold welding or fusion occurs at the interface between metal surfaces under pressure and, during the subsequent relative motion, these contact points are ruptured and fragments of metal are removed. These fragments, because of their small diameter and the heat due to friction are immediately oxidized. This process is repeated resulting in the loss of metal and accumulation of oxide residue.

Figure 8.11 Schematic Illustration of the Oxidation-wear Theory of Fretting Corrosion The oxidation-wear concept is based on the hypothesis that most metal surfaces are protected from atmospheric oxidation by a thin, adherent oxide layer. When metals are placed in contact under load and subjected to repeated relative motion, the oxide layer is ruptured at high points and results in oxide debris. It is assumed that the exposed metal re-oxidizes and the process is repeated.

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Tuition Notes for 3.1U Course Chapter 8 This type of corrosion could occur in the metal adjacent to clamps and collars of risers, conductors and caissons if there is the slightest movement underneath them. See Figure 8.12.

Figure 8.12 Possible Fretting Corrosion between Riser and Riser Clamp 1.8

Erosion Corrosion

This is a self-explanatory name for a form of corrosion that results from a metal being attacked because of the relative motion between an electrolyte and a metal surface. Examples of this type of corrosion are attributable to mechanical effects, such as, wear, abrasion and scouring. Soft metals such as, copper, brass, pure aluminium and lead are particularly vulnerable. Two main forms of erosion corrosion are: Corrosion associated with laminar flow Damage caused by impingement in turbulent conditions A laminar flow will cause several effects: The ionic distribution in the double layer is carried away by the flow and equilibrium cannot be established which leads to an increased rate of dissolution. Figure 9.1 Chapter 9 refers Where the increased flow replenishes aggressive ions such as chloride and sulphide this has a detrimental effect and corrosion rates increase

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Tuition Notes for 3.1U Course Types of Corrosion If the flow contains any solid particles protective layers may be scoured away causing excessive corrosion The alternative to this is that it is sometimes possible in pipes for the deposit of silt or dirt to be prevented thus preventing the formation of any differential-aeration cells in the crevices beneath A possible beneficial effect is that more oxygen is carried to the area, which minimises the formation of differential-aeration cells that are normally a common cause of attack. Stainless steels in particular benefit from improved corrosion resistance because oxygen replenishment maintains its protective oxide film Another possible beneficial effect is where a steady supply of inhibitor is concentrated within the flow, as in a pipeline for example These combined circumstances make the effects of laminar flow unpredictable. Taking the case of turbulent flow, however the situation is much more straightforward. The fluid molecules now impinge directly on the metal causing wear. This obviously increases the corrosion rate This effect can easily occur inside a pipe because turbulence can be caused by, sudden changes in bore diameter, sudden changes in direction (i.e. pipe bends), a badly fitted joint or gasket, any deposits that may be either circumferential welds or silt deposits. Figure 8.13 refers.

Figure 8.13 Effects of Flow in Pipes

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Tuition Notes for 3.1U Course Chapter 8 1.9

Corrosion Fatigue

There are many similarities between corrosion fatigue and stress corrosion cracking but the most significant difference is that corrosion fatigue is extremely non-specific. As detailed in Chapter 4 fatigue affects all metals causing failure at stress levels well below the UTS. In aqueous environments it is frequently found that a metal’s fatigue resistance is reduced, or even that it no longer has a fatigue limit. Summarising the stages in the development of a fatigue crack as discussed in Chapter 4 yields: Firstly the formation of slip bands Next the nucleations of an embryo crack in the order of 10 µm long Then the extension of this crack along favourable paths Finally macroscopic, 0.1 to 1 mm, crack propagation in a direction at right angles to the maximum principal stress that leads to failure Corrosion fatigue can occur in any of the three corrosion states indicated by the Pourbaix diagram as shown in Chapter 10, Figure 10.1, it can also occur at stress levels much lower than those for stress corrosion cracking (SCC). It is also true that while SCC growth rates are independent of the stress intensity factor during much of the crack growth, fatigue crack growth is always affected by it. It is thought that the use of cathodic protection systems that place the metal in the immune state and over time cause calcareous deposits to form that tend to inhibit crack growth ensure that the structures are resistant to corrosion fatigue. 1.10 Biological Corrosion Corrosion by marine biological action can be initiated in various ways: By the production of corrosive substances like hydrogen sulphide or ammonia, which result in direct chemical attack on the metal By producing or actually being a catalyst in the corrosive action By the reaction of sulphate-reducing bacteria (SRBs) under anaerobic conditions o The most important of these are the bacteria Sporovibrio desulfuricans. These thrive in the reduced oxygen conditions created under heavy accumulations of marine growth, under thick deposits of corrosion products, or under mud There are indications that because oxygen is unable to diffuse through the heavy marine growth the effect of this organism is to take the place of oxygen in the usual cathodic reaction By the formation of concentration cells around and under the organisms

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Tuition Notes for 3.1U Course Types of Corrosion

Bibliography Underwater Inspection M Bayliss, D Short, M Bax E & F N Spon Corrosion for Students of Science and Engineering K R Trethewey & J Chamberlain Longman Scientific & Technical

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Tuition Notes for 3.1U Course Chapter 9

CHAPTER 9 Factors Affecting Corrosion Rates 1

Polarisation and Corrosion Rate

When a metal is exposed to an aqueous solution containing ions of that metal, both oxidation of metal atoms to ions and reduction of metal ions to atoms occurs on its surface according to the formula: Men+ + ne-

Me

This means that there are two reactions involving the flow of electrons and the rate at which these reactions occur can be given by two current densities. The necessity for using current density as a measurement of corrosion currents can be demonstrated by considering two pieces of metal; one say, of 10 mm2, the other of 1 mm2 and suppose they both corrode such that the current flow is 10 electrons per second. The smaller piece will obviously corrode 10 times faster than the larger piece. Thus the surface area of the corroding metal must be taken into account when measuring current. The unit of current density is Am-2 (amps per square meter) The corrosion rate and the current density are directly related; which makes the topic quite important when considering the long-term deterioration of metals in aqueous solution These two current densities can be indicated as forward and reverse reaction currents thus: i and i and at equilibrium (Eo) exchange current density.

i = i = io and io is known as the

If a net current (i) is applied to the surface i ≠ I this applied net current will be the difference between the forward and reverse currents. This difference in current changes the electrode potential and this new potential is given the value Ei and the electrode is said to be polarized. The change in electrode potential is called polarization and is given the Greek letter η (eta). η = Ei - Eo There are two main polarization components to consider. Concentration Polarization Caused by the difference in concentration between the layer of electrolyte nearest the electrode surface and the bulk of the electrolyte. See Figure 9.1

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Figure 9.1 Concentration Polarization (The Double Layer) o The initial polarization at the anode produces a surfeit of positive cations that in turn causes a non-homogeneous distribution of ions with the most densely populated layer nearest to the electrode being the Helmholtz and the second more diffuse being the GuoyChapman. In this layer the potential changes exponentially. This distribution is commonly referred to as the double layer Activation Polarization Caused by a retardation of the electrode reaction. The polarization of an anode is always positive and that of a cathode always negative. Later in these notes the monitoring of corrosion in a seawater environment will be discussed and reference will be made there to measuring both potential and current density 2

Environmental Factors Affecting Corrosion Rates

The corrosion rate is predictable within certain parameters and corrosion engineers work this out when designing a protection system. There are however, environmental factors that effect the overall corrosion reaction and these will be indicated here. Specifically the factors considered will be: Temperature Water Flow Rate The pH of the Water 2.1

Temperature

Most chemical reactions are speeded up by an increase in temperature. Thus temperature cycling and temperature differences will also have this effect.

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Tuition Notes for 3.1U Course Chapter 9 Hot risers, exhaust and cooling water dumps are all sites that can and do corrode more quickly than the remainder of typical offshore structures. Studies undertaken by the Dow Chemical Company showed that the corrosion rate of mild steel and a selected low alloy steel, in a standard brine solution at a pH of 9.4, approximately doubled as the temperature was increased from 180o F (82o C) to 250o F (121o C). Therefore, components like cooling water outlets and hot risers are particularly susceptible to corrosion and must be inspected regularly. The effect of seawater temperature is illustrated by the graph in Figure 9.2.

Figure 9.2 The Effect of Temperature on Corrosion of Steel in Seawater 2.2

Water Flow Rate

In general if the flow rate is increased the rate at which metal is removed is also increased. If there is impingement of the flow on the metal or aeration takes place in the region of the surface, then a very much larger rate of metal removal is experienced locally. The pitting of ships propellers and pump and dredger impellers are general examples of this. Tests carried out by P Ffield show how the corrosion of steel pipes carrying seawater is effected in a straightforward way by increasing the velocity of the flow. Figure 9.3 illustrates his findings.

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Figure 9.3 Effect of Seawater Velocity on Corrosion of Steel at Ambient Temperature Exposed 38 Days 2.3

The pH Value of the Water

The corrosion rate of metals in directly affected by the pH value of the electrolyte. Steel for example corrodes least when in a solution that has a pH between 11 and 12. A resume of the pH system is laid out below. The resume starts by considering water, which is neutral. Water is a neutral molecule in which two atoms of hydrogen combine with one of oxygen, there is a limited amount of dissociation into hydrogen ions and hydroxyl ions in the normal course of events and this can be noted in the form of an equilibrium thus: H2O

H+ + OH-

The Law of Mass Action can be applied to this equilibrium process and assuming the concentration of water in dilute solution is constant given Standard Temperature and Pressure (STP) a new equation for water can be written thus: [H+]. [OH-] = constant

(I)

This constant has been measured experimentally as 10-14 (STP) and this value and the relationship equation form the basis of a scale of acidity. All acids have one common property that is the presence in aqueous solution of the hydrogen ion. The opposite of acid is alkali or basic, which means that acids are neutralised by alkalis and that alkalinity, is associated with hydroxyl ions.

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Tuition Notes for 3.1U Course Chapter 9 Water as indicated by the equilibrium equation represents a neutral substance as it contains both acid, (H+) and alkali (OH-) in equal quantities. The modern method of defining acidity is by means of a term called pH, which indicates the amount of hydrogen activity. It is measured on a scale of 0 to 14 thus: -

Figure 9.4 pH Scale

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Bibliography Underwater Inspection M Bayliss, D Short, M Bax E & F N Spon Corrosion for Students of Science and Engineering K R Trethewey & J Chamberlain Longman Scientific & Technical

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Tuition Notes for 3.1U Course Chapter 10

CHAPTER 10 Corrosion Protection 1

Corrosion Protection

There are numerous methods for preventing corrosion including, coatings, inhibitors (controlling the electrolyte), selective design, anodic protection and cathodic protection. Before considering these methods a brief examination of the way in which the corrosion process is influenced by the two main variables; the electrode potential and the pH value will assist in understanding the various protection methods. These data are often presented in diagrammatic form known as Pourbaix diagrams. These diagrams are obtained from laboratory tests carried out under controlled conditions of constant temperature and no flow.

Figure 10.1 Pourbaix Diagram for Iron in Water It can be seen from Figure 10.1 that there are three distinct possible states of corrosion depending on electrode potentials and pH values:

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Tuition Notes for 3.1U Course Corrosion Protection Corrosion At intermediate electrode potentials and over a very wide range of pH values corrosion takes place and metal is removed Passivity At higher electrode potentials and over a wide range of pH values, there is a passivity region. This is the region in which a corrosion product film is formed, that in most cases is an oxide film. It is worth noting that the diagram only indicates that an oxide film is formed; it does not mean that the oxide film gives protection. The properties of the film must be known in order to determine this Immunity At low electrode potentials and over almost the whole of the pH range, the rate of corrosion is so low that the metal is said to be immune 2

Cathodic Protection

Apart from the three stages indicated by Figure 10.1 it is also possible to determine basic strategies for preventing corrosion. Making the electrode potential more positive will produce passivation at point C Making the electrode potential more negative will produce immunity at point B Making the electrolyte more basic will produce passivation at point D Altering the electrical potential to produce passivation or immunity by the methods of cathodic or anodic protection is the most useful technique for offshore structures. In designing a Cathodic Protection system the system designer starts by determining an acceptable corrosion rate (rρ) this information is input to a graph to determine a value for current density (Iρ). This level of current density will ensure the required corrosion rate is achieved. The electric potential to achieve this current is approximately -850 mV. Now it may seem that potentials more negative that –850 mV (Ag/AgCl) would produce even less metal loss. There are two reasons why it is not prudent to use very much more negative potentials. At potentials much more negative than –1000 mV (Ag/AgCl) the possibility of hydrogen evolution exists and this can cause hydrogen embrittlement Secondly large currents are associated with more negative potentials that produce high local concentrations of hydroxyl ions that often damage barrier coating such as paint if it is present These last two points are more likely to occur with an electrical impressed current protection system but non-the-less are quite valid which makes the choice of –800 to –900 mV (Ag/AgCl) a valid design parameter in all cases for offshore platforms.

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Tuition Notes for 3.1U Course Chapter 10

2.1

Cathodic Protection: The Sacrificial Anode Method

With this method of corrosion prevention the entire structure is made into the cathode in a massive corrosion cell as indicated diagrammatically in Chapter 7, Figure 7.7. The structure will therefore not corrode but at the expense of the anode, which is sacrificed providing the electron flow and gives the process its name. Refer to Figure 10.2

Figure 10.2 Sacrificial Anode Cathodic Protection The anode must be picked from the appropriate galvanic series. The most appropriate metals are zinc, aluminium and magnesium. This method of corrosion protection is almost as straightforward as that. The main question is how much anode material will be required? This question has two parts: How large a surface area must the anodes protect? How long will the protection last? To answer the question an example will be given: An uncoated steel offshore drilling platform has a sacrificial anode cathodic protection system installed designed to last for 10 years. What anode material should be used and how many anodes are required? o Total wetted surface area of structure Minimum number of anodes required

= 2500 m2 = 2510

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Tuition Notes for 3.1U Course Corrosion Protection 2.1.1 Advantages and Disadvantages of Sacrificial Anode Systems The advantages and disadvantages of sacrificial anode systems are summarised in Table 10.3 Advantages and Disadvantages of Sacrificial Anode Systems Advantages

Disadvantages

No external electric power required

Current output decreases with time

No danger of overprotection

Comparatively difficult to increase protection by retro-fitting anodes

No running costs

Initial costs are comparatively high

Active from day of immersion

Adds considerable weight and drag to the structure

A well proven and reliable method Table 10.3 Advantages and Disadvantages of Sacrificial Anodes 2.2

Cathodic Protection: Impressed Current Method

An Impressed Current Cathodic Protection (ICCP) system works on the same principal as the sacrificial system in that the structure is made to be the cathode. However in the case of the ICCP system the necessary potential and current flow is provided by a DC generator rather than by a galvanic coupling. This system can be made to be self-adjusting by incorporating reference electrodes into the circuit that measure potential. The potential can vary depending on the circumstances; if the structure has a coating initially that in subsequent service becomes damaged this will increase the exposed surface area needing to be protected. The control unit can deal with this by increasing the current density. If on the other hand there were a reduction in the surface area; as for instance a calcareous deposit building up, there would be less surface area exposed and the current requirement would be less. In both cases the reference electrode provides the means of monitoring the potential, which varies proportionally according to the current. Figure 10.4 shows the system diagrammatically.

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Figure 10.4 The Principle of Impressed Current Cathodic Protection Using a Potentiostat The anode material is selected from the bottom of the galvanic series not the top. Materials such as titanium, Platonised niobium and lead/silver alloys are used. The anode and supply cables are insulated from the structure to prevent any of the problems associated with over-protection. Noble metals, virtually non-consumable anodes, can be used in this system because in electrolytes of pH 7 or less the anode reaction is the oxidation of water, rather than metal dissolution: 2H2O

O2 + 4H+ + 4e-

In electrolytes of pH values greater than 7 (alkaline solutions) the reaction is the oxidation of hydroxyl ions: 4OH-

O2 + 2H2O + 4e-

In seawater the reaction is usually the oxidation of chloride ions to chloride gas: 2Cl-

Cl2 + 2e-

Table 10.5 lists some properties of impressed current anode materials.

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Tuition Notes for 3.1U Course Corrosion Protection

Material

Consumption

Recommended Uses

(Kg yr-1) 8 x 10-6

Marine environments and high purity liquids

High Silicon Iron

0.25 – 1.0

Potable waters and soil or carbonaceous backfill

Steel

6.8 – 9.1

Marine environments and carbonaceous backfill

Iron

Approx 9.5

Marine environments and carbonaceous backfill

Cast Iron

4.5 – 6.8

Marine environments and carbonaceous backfill

Lead-Platinum

0.09

Marine environments

Lead-Silver

0.09

Marine environments

Graphite

0.1 – 1.0

Marine environments, potable water, and carbonaceous backfill

Platinum Platonised Metals

Table 10.5 Some Impressed Current Anode Materials and Their Properties (From Brand) 2.2.1 Practical Considerations for Installing ICCP Systems Anodes made from materials such as listed in Table 10.5 are capable of supplying high current densities and it would be possible to protect a structure with a few large anodes supplied with a high current. However, in practice anodes are usually distribute at regular intervals over the whole structure. This is because: The high current density that would be present in the immediate vicinity of a single anode could damage paint surfaces and possibly cause embrittlement as previously discussed. o The use of more anodes reduces the current density for each one and reduces the probability of this type of damage Offshore structures have a reasonably complicated geometry that makes it difficult for corrosion engineers to predict the total distribution potentials. Therefore it is prudent to use more anodes, each one protecting a smaller area thus minimising the areas at risk of inadequate protection

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Tuition Notes for 3.1U Course Chapter 10 o When designing the system should the corrosion engineers have any doubts about protecting any particular area of the structure sacrificial anodes may be installed to work in conjunction with the ICCP system The ICCP system installed on the Claymore platform was designed to provide 160 mA m-2 utilising 55 platinum-iridium anodes and 12 reference electrodes. Also the Murchison platform uses 100 anodes and 50 reference electrodes. In general in the North Sea the most common anode materials are Platinum sheathed Titanium and Lead/Silver alloys. It is vitally important that the power supply is connected with correct polarity. The negative terminal must be connected to the structure and the positive terminal must be connected to the anode. Should these connections be reversed the structure would corrode catastrophically. Figures 10.6 and 10.7 refer.

Figure 10.6 Diagrammatic Layout of an Impressed Current Cathodic Protection System

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Figure 10.7 Impressed Current Cathodic Protection Distribution of Anodes and Dielectric Shield As indicated in paragraph 2.2.1 the actual distribution of the anodes on any structure may be either: Platform Based Here numerous anodes are attached to the structure at intervals around it in similar fashion to sacrificial anodes but ensuring that they are insulated from the structure. Figure 10.7 refers. o Two problems are associated with this method. One is the possibility of ‘shadow’ areas where inadequate protection is provided. This problem can be solved by the use of sacrificial anodes complementing the ICCP system as indicated earlier. The second problem is the possibility of current flowing directly from the anode to the adjacent structure. This could cause embrittlement as discussed earlier and to avoid this dielectric shields are employed to insulate the structure electrically. Also the current is limited by design because each anode is positioned to provide adequate protection for the local area only. This limits as well the possibility of embrittlement and coating damage. See Figure 10.7 o There is also a diver safety consideration in that these anodes are at about 80 V potential with some 1000 A current. If divers are employed adjacent to any of the anodes they should be isolated from the system Remote from the Structure A number of anodes may be placed on the seabed at a designated distance from the structure. Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 10 o This method avoids the possibility of current flowing directly from the anode to the adjacent structure but there being fewer anodes the current density is higher and therefore there is still a possibility of coating damage and embrittlement. o As discussed in paragraph 2.2.1 design considerations generally favour more anodes distributed around the structure. o There is a safety issue with divers but as the anodes are some distance away from the structure it may be possible to ensure safety by imposing an exclusion zone around the anode. See Figure 10.8

Figure 10.8 Diagram of ICCP System with Anodes Remote from Structure 2.2.2 Reference or Control Electrodes These electrodes are commonly zinc, silver/silver-chloride (Ag/AgCl) or (SCC) or copper/copper-sulphate (CSE). CSE is favoured in applications with reinforced concrete. Reference or control electrodes are vital components of any ICCP system. They determine the current required from the power source, without these items the system cannot provide a quantifiable degree of protection. Figure 10.9 refers.

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Figure 10.9 Zinc Reference Electrode Installed On an Offshore Structure 3

Using Coatings to Protect the Structure

Coatings form a barrier between the electrolyte and the surface of the protected structure. They may be paints, organic films, varnishes, metal coatings or enamels and even sheathing. It is surprising how effective coatings can be when consideration is given to the thickness of a typical paint coat. This may be only in the order of 25 to 100 microns thick for some applications. 3.1

Paints

When paint is applied to a metal surface it presents a barrier to air, moisture and ions aggressive to the metal. However, paint cannot provide a complete barrier to oxygen or water. In time these will penetrate through to the surface of the metal. Any paint system used underwater must have a strong bond onto the metal surface and therefore high quality metal surface preparation is required such as SA 3. The bonding between successive coats must also be strong and the topcoats must provide as impervious a barrier to the electrolyte as is possible. This last is achieved by ensuring the constituents making up the topcoats have very low water absorption and transmission coefficients. Coal Tar Epoxides are used extensively on offshore structures. They consist of coal tar and epoxide resin for the binder. These coatings are highly impermeable to water and resistant to attack by most chemicals and hydroxyl ions (that are produced by the cathodic reaction)

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Tuition Notes for 3.1U Course Chapter 10 Zinc coatings utilising a combination of zinc dust and complex silicates with a solvent-based self-curing binder give good protection to steel surfaces. These coatings are frequently over-painted by another system and are used on components such as ladders in a marine environment Concrete is used to provide a protective coating to pipelines where it provides a passive environment for the steel pipe as well as adding weight. Metallic coatings such as galvanising, using zinc impose a continuous barrier between the metal surface being protected and the surrounding environment. These coatings may be applied in a number of ways. Electroplating utilises a bath of salts as an electrolyte. The component and rods of the plating metal are immersed in the electrolyte and a potential is applied between the component and the rods. The component becomes the cathode and the rods the anode so metal ions of the plating material deposit from the solution onto the component Hot dipping involves the component being immersed in a bath of molten coating metal. Galvanising is accomplished by this method. See Figure 10.10

Figure 10.10 Galvanising Spray coats utilise a specialised torch that is fed with wires of the coating metal that are melted and blown out by it. The molten metal is expressed in the form of droplets travelling at 100 to 150 m s-1 that flatten and adhere on impact with the component Cladding uses metal skins laminated onto the component. The skin can be applied by o Rolling o Explosive welding o Buttering (building up a welded coat on the surface to be protected) o Sheathing Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Corrosion Protection Aluminium roll-bonded to duralumin is marketed as Alcad. o Some offshore risers are sheathed with Monel (cupronickel) See Figure 10.11

Figure 10.11 Monel Cladding on an Offshore Riser Diffusion requires the component to be heated to just below the melting point of the coating metal in the presence of the coating in powder form and in an inert atmosphere. The component is allowed to ‘baste’ for several hours and the coating diffuses into the surface of the component. 4

Inhibitors (Controlling the Electrolyte)

Remember the Pourbaix diagram indicates three methods for preventing corrosion: Making the electrode more positive Making the electrode more negative Changing the electrolyte pH This section will outline methods for changing the electrolyte. Also remember there are four processes in metal corrosion: The anodic reaction The cathodic reaction Ionic conduction through the electrolyte Electron conduction through the metal Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 10 Only the first three are affected by the electrolyte, electron conduction through the metal is not considered here. The properties of the electrolyte that can be affected by using inhibitors are: The conductivity of the electrolyte The pH of the electrolyte The interaction of the electrolyte with the metal surface, attacking or strengthening passive films As an example of how this can be achieved consider steel in seawater. If distilled water is substituted for the seawater the conductivity and pH of the electrolyte is reduced and a passive film will form on the surface of the steel. 4.1

Anodic Inhibitors

Anodic inhibitors increase the polarisation of the anode by reaction with the ions of the corroding metals to produce either thin passive films or salts of limited solubility that coat the anode. See Figure 10.12

Figure 10.12 Anodic Inhibitor 4.2

Cathodic Inhibitors

Cathodic inhibitors affect both normal reactions In one effect the inhibitor reacts with hydroxyl ions to precipitate insoluble compounds on the cathodic site thus blanketing the cathode from the electrolyte and preventing access of oxygen to the site. In the other reaction increasing the polarisation of the system controls the evolution of hydrogen. This forms a layer of adsorbed hydrogen on the surface of the cathode. This type of inhibitor may allow hydrogen atoms to diffuse into steel and cause hydrogen embrittlement

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4.3

Adsorption Inhibitors

Adsorption inhibitors interrupt the ion flow from the metal surface by forming long organic molecules with side chains that are adsorbed and desorbed from the metal surface. These bulky molecules can limit the diffusion of oxygen to the surface, or trap the metal ions on the surface, stabilise the double layer and reduce the rate of dissolution In general anodic inhibitors are more efficient than cathodic ones. 5

Corrosion Protection by Design

This aspect of corrosion protection has been indicated earlier in Chapter 8. The methods employed to protect structures from corrosion can be summarised thus: Avoid all unnecessary bimetallic corrosion cells Avoid differential-aeration cells (crevices, debris traps, inadequate drainage, etc.) Avoid stray currents from electrical machinery or conductors Choose the material with the best properties for the environment 6

Anodic Protection

In this method of corrosion protection a potential is applied to the anode that maintains it in the passive range of the Pourbaix diagram. This allows the formation of a passive film that is robust enough to provide a barrier to the normal corrosion process. However, this film is unreliable for steel in aqueous solutions and therefore is not used on offshore structures. Aluminium does form such a film naturally and some types of aluminium can benefit from this because the passive layer is sufficiently robust to be relied upon.

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Bibliography Underwater Inspection M Bayliss, D Short, M Bax E & F N Spon Corrosion for Students of Science and Engineering K R Trethewey & J Chamberlain Longman Scientific & Technical

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Tuition Notes for 3.1U Course Chapter 11

CHAPTER 11 Corrosion Protection Monitoring 1

Monitoring Corrosion Protection

It has been indicated several times during this discussion on corrosion that there are variables presented in-service that cannot be adequately predicted. Therefore a monitoring regime is necessary to ensure that the designed corrosion protection system is operating to its design specifications and that there are no in-service effects interfering with this. The amount of current from sacrificial anodes or from an impressed current system required for protection varies: From metal to metal With the geometry of the structure With differences in sea water environment (temperature, pH value etc.) With any other factors that affects the resistance of the circuit Since the amount for current required for protection of any structure cannot be accurately predicted or distributed evenly through the structure, the method of checking for adequate protection is to measure the potential and current density of the structure at various places. 1.1

Inspection Requirements

Monitoring or inspection requirements for corrosion protection systems are therefore as follows: Visual inspections of the anode (both sacrificial and impressed current nodes) for wear Visual inspection of electrical connections of the sacrificial system to see that it is intact and of the impressed current system to ensure that there are no breaks in the insulation of the supply cables Potential measurements on the structure to confirm that it is still the cathode by confirming the readings obtained are in the immunity range of the Pourbaix diagram Current density measurements to confirm that the impressed current system is providing adequate protection Visual and ultrasonic inspection for corrosion damage including pitting and loss of wall thickness The specific visual inspection requirements are detailed in Chapter 17 Visual inspection. The ultrasonic requirements are covered in Chapter 15 The potential measurements usually referred to as Cathode Potential (CP) readings are obtained by: Taking contact readings with a CP meter Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Corrosion Protection Monitoring o By hand employing a diver with a hand-held instrument o By mounting a contact probe on an ROV Taking proximity readings with a proximity probe mounted on an ROV Monitoring proximity readings via remotely mounted permanent sensors with readout in a surface control room Current density measurements and monitoring are obtained by: Taking current density readings normally with an ROV mounted sensor and usually for a specific requirement. This method is not used for regular inspections Monitoring potential and current through remotely mounted electrodes incorporated into the impressed current system 2

Cathode Potential Measurement

The cathode potential is measured by using a reference electrode incorporated into an instrument that has a readout calibrated in mV. As stated in the previous Chapter these electrodes are commonly: High purity zinc Silver/silver-chloride (Ag/AgCl) or (SCC) Copper/copper-sulphate (CSE) (this is more favoured for concrete structures) 2.1

High Purity Zinc Electrodes (ZRE)

High purity zinc (99.9% pure) is most commonly used with remote mounted monitoring systems as shown in Chapter 10 Figure 10.9. The site for mounting the electrode is selected because it is either, a representative site, it is an area of marginal protection or it is an area of high stress and it is installed as part of the impressed current system. The electrode is connected to a meter in the surface control room. See Figure 11.1

Figure 11.1 High Purity Zinc Electrode (ZRE) Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 11 2.2

CP Readings Utilising Silver/silver-chloride (Ag/AgCl) Electrodes

The most common reference electrode used in offshore corrosion monitoring is Silver/silver chloride. This electrode is used extensively for both contact and proximity applications whether diver or ROV deployed. Ag/AgCl electrodes, most frequently referred to as half-cells (because they form a ‘cell’ when the meter is connected to the cathode) are utilised in several contact CP probes, including the Bathycorrometer, the Morgan Berkeley Rustreader, that are hand held, and ROV probes. They are commonly used as proximity probes also. The probe contact tip is placed on the cathode and the meter gives the readout in mV of the electrical potential between it and the halfcell. Figure 11.2 refers for a hand-held meter. Figure 11.3 illustrates an ROV contact probe and Figure 11.4 diagrammatically shows the proximity method. When taking proximity CP readings it is vital that a sound electrical connection is made between the structure and the positive terminal of the surface control room installed meter, as indicated in Figure 11.4

Figure 11.2 Diver-held CP Meter (Bathycorrometer or similar)

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Tuition Notes for 3.1U Course Corrosion Protection Monitoring

Figure 11.3 Contact CP Reading Taken By an ROV

Figure 11.4 Proximity CP Measurement 3

Current Density Measurements

Current density may be measured using a specialised probe mounted on an ROV. This type of inspection would be undertaken for a specific purpose such as investigating a particular area of the structure that was suspected of being under-protected or following up a visual inspection that had identified more

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Tuition Notes for 3.1U Course Chapter 11 corrosion than was anticipated. Specific procedures will be provided for this type of survey. As stated earlier impressed current systems have reference electrodes installed to monitor current flow and potential. Figure 10.10 Chapter 10 shows a ZRE monitoring potential and Figure 11.5 illustrates a monitored anode. A monitored anode is a sacrificial anode that is isolated electrically from the structure and is connected via an insulated cable to the surface control room. Thus the current can be constantly monitored.

Figure 11.5 Monitored Electrode 4

Calibration Procedures for Hand-held CP Meters

It is necessary to calibrate CP meters to ensure that the readings obtained are accurate and comparable with other and previous readings. A standard method of calibration has been adopted in the offshore industry for this purpose. This procedure is detailed here. 4.1

Necessary Equipment

Three Calomel Electrodes complete with electrical connectors, or three screwon calomel cells for hand-held CP meters (these are available for the Bathycorrometer and can be provided with screw in electrical connectors, which should be specified. The electric connector is provided so that the cells can be proven as described below.) High impedance (10 ΜΩ) voltmeter Zinc (99.9% pure) block with clamp and electrical connector Plastic bucket filled with fresh seawater (not from fire main which could contain inhibitors) Log sheets Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Corrosion Protection Monitoring 4.2

Procedure

The first part of the procedure proves that the calomel cells are chemically saturated and sufficiently stable enough to be used as reference cells. 4.2.1 Proving the Calomel Cells There are different types of cells available. One type is specifically designed for use with a Bathycorrometer. This type has a solid polymer body protecting the calomel cell. The procedure outlined below also applies to this type of cell; however it is not possible to visually confirm they are fully saturated with solution. They are sealed, and to confirm they are saturated it is necessary to unscrew a sealing cap to gain access to the solution reservoir. Visually inspect the electrodes to ensure they are undamaged and full of solution. The solution is potassium chloride (K Cl) and if the solution is saturated or supersaturated solid crystals may be seen in the phial. (Commonly the phials are glass or clear plastic) Label the electrodes 1,2 and 3 Soak the electrodes in the bucket for 24 hours, being careful to immerse each one only as far as the filling hole in the phial While the electrodes continue to soak connect electrode 1 to the negative terminal of the voltmeter and electrode 2 to the positive terminal and record the reading Repeat the test with each permutation of electrodes –1 and 3 –2 and 3 o Acceptable readings between any pair of electrodes is 0 ± 2 mv

Figure 11.6 Proving Calomel Reference Cells If all the readings are within this range any electrode may be used If one reading is out of this range the electrode not in that pair is the one to use Issue 1.0 Rev 0 Issue Date 01/09/2006

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Tuition Notes for 3.1U Course Chapter 11 If one reading is in range either of the electrodes in that pair can be used If all of the readings are either replace all the calomel cells or flush out the phials with pure distilled water, obtain a new saturated solution of potassium chloride, refill the phials and re-test On completion of the entire procedure rinse the electrodes in fresh water. Figure 11.6 refers. The second part of the procedure confirms the calibration of the CP meter. 4.2.2 Calibration of the Meter The calibration procedure for a contact CP meter is basically the same whether it is diver hand-held or ROV deployed. 4.2.3 Calibration of a Bathycorrometer There is slight difference in the application if the meter is a Bathycorrometer being calibrated with the specifically designed screw-on cells. In this case the following procedure applies. Fully charge the CP meter batteries and soak in fresh seawater (not drawn from the fire main) Remove the contact probe tip from the meter Screw the calomel reference electrode onto the Bathycorrometer instead of the tip Immerse the meter in the bucket at least far enough to submerge the semi-permeable membrane. (The meter display may be left out of the water to assist taking readings.) Allow time for the meter to stabilise (approximately 10 minutes maximum) The voltage potential between the reference electrode and the meter’s own Ag/AgCl cell is read off the meter display directly. Record the reading on the log o Acceptable readings are between 0 to -10 mV. (The reading will be negative as the Ag/AgCl cell built into the hand-held meter is connected to the positive terminal of the meter). The calibration of other types of contact CP meters is by comparison. The procedure is outlined under paragraph 4.3 below. 4.3

Overall Calibration of any CP Meter

Select the proven calomel electrode and immerse the tip for 30 minutes into a plastic bucket on deck Take a zinc block, attach a clamp and electric wire and place the block into the same bucket Connect the calomel electrode to the negative terminal of a high resistance voltmeter via the electric cable attached to the electrode

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Tuition Notes for 3.1U Course Corrosion Protection Monitoring Connect the zinc block to the positive terminal of the voltmeter via its electric connector. (Immerse only the zinc, not the clamp or connector) Take a reading from the voltmeter. Acceptable readings are –1.00 V ± 5 mV. Record the reading on the log Remove the zinc block and disconnect it from the clamp Soak the CP meter assembly in a bucket of fresh seawater for 30 minutes Place the zinc block into the same bucket as the CP meter and make submerged contact between the probe tip and the zinc. Take a reading from the CP meter. This reading should be the same as that recorded from the calomel ± 10 mV (this proves the CP meter by comparison) Record the reading on the log Remove the zinc and calomel cells from the seawater, wash in fresh water, dry and store. 4.4

Calibration of Ag/AgCl Proximity Probes

Before initiating this procedure ensure that the insulation on the conductors for the proximity cell is intact. This may be achieved by using an insulation test meter. The cable must be properly insulated to avoid any possibility of the copper conductor being exposed to seawater and affecting the readings. Select a proven calomel cell and immerse the tip in a bucket of fresh seawater for 30 minutes Immerse the Ag/AgCl proximity probe in the same bucket for the same time Connect the negative terminal of the high resistance voltmeter to the Ag/AgCl half-cell Connect the positive terminal of the voltmeter to the calomel electrode Take the reading. Acceptable readings are 0 ± 10 mV Remove the calomel electrode and immerse the zinc block (only) positioned 100 mm from the Ag/AgCl half-cell. The zinc block is connected to the positive terminal of the meter system via the clamp and electrical connection Take the reading. Acceptable readings are –1.00 V to 1.050 V 5

Operating Procedures

To ensure that accuracy is maintained and that repeatable results are obtained CP monitoring methods should follow a procedure as follows. Ensure any self-contained meters are fully charged and maintain a battery-charging log. (Usual requirements for charging batteries for battery-operated equipment is 14 to 16 hours from fully discharged)

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Tuition Notes for 3.1U Course Chapter 11 Ensure the probe tip for contact meters is sharp (hand-held meters are usually supplied with spare tips) Soak meters and half-cells for a minimum of 30 minutes before use. (This allows time for ion penetration through the semi-permeable membranes.) Confirm the calibration of the system in use according to the appropriate calibration procedure. Record the results on the appropriate log sheet Record meter serial number and any other specified details on the appropriate log sheet Take a reference reading on zinc on the inspection site prior to starting the survey For each contact reading ensure that there is correct metal-to-metal contact between the probe tip and the cathode surface. With proximity probe surveys ensure there is a solid electrical connection to the structure connected to the positive terminal of the surface instrument For proximity probe readings ensure the standoff between the probe and the cathode is correct During the course of the survey ensure that each reading is correctly recorded on the appropriate log On completion of the survey take another reference reading on zinc Recover the equipment, wash in fresh water, dry and store. Charge any battery-operated equipment as necessary and complete the batterycharging log Notes: Morgan-Berkley meters can be left soaking in a solution of silver chloride, on trickle charge continuously if required If a large number of readings are being taken it is prudent to take check readings periodically during the survey 5.1

Normal Cathode Potential Readings Against Ag/AgCl

Following are the normal range of readings expected during a survey of a steel structure Over-protected structure