CCI Feasibility Study for 500 KV AC Underground Cables

CCI Cable Consulting International Ltd

Feasibility study for 500 kV AC underground cables for use in the Edmonton region of Alberta, Canada

PO Box 1, Sevenoaks TN14 7EN United Kingdom

ER 381

19th February 2010

TITLE:

FEASIBILITY STUDY FOR 500 kV AC UNDERGROUND CABLES FOR USE IN THE EDMONTON REGION OF ALBERTA, CANADA

REPORT No:

ER 381

CUSTOMER:

AESO

AUTHORS:

Alan Williams BSc CEng MIET Brian Gregory BSc CEng FIEE

DATE:

18 February 2010

INTRODUCTION CCI has been engaged to perform a feasibility study into the use of 500 kV underground cables for the Edmonton region of Alberta. The design requirements used within this study are generic and based on those of the 500 kV 3,000 MW system known as the “Heartland Project”. This document contains a description of the available cable technology, recommendations on the feasibility of the cable technology and how underground cable technology needs to be developed so as to be suitable for use in the Edmonton region. Also included are:  Definitions and glossary (Section 16) for words that have been Capitalised.  An appendix recording individual studies, including:  Total cost estimates (in 2009 Canadian dollars) for nine scenarios comprising different proportions of underground cable and overhead line, which were provided by the Heartland Project Team (HPT) based on estimated cable system costs provided by cable manufacturers and estimated civil cable installation costs provided by HPT. HPT also provided the estimated costs of the overhead line and all of the other equipment required for each scenario.  Preliminary project schedules, which were provided by HPT. Distribution:

AESO, HPT, CCI Page 1 of 310

Cable Consulting International Ltd Registered in England and Wales No. 4234974 Registered office: 74 College Road, Maidstone, Kent, ME15 6SL, United Kingdom




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CONTENTS INTRODUCTION .................................................................................................................................... 1 1 EXECUTIVE SUMMARY............................................................................................................. 13 1.1 Introduction............................................................................................................................. 13 1.2 Method of approach ................................................................................................................ 14 1.3 Technical feasibility findings.................................................................................................. 16 1.3.1 Choice of cable technology............................................................................................. 16 1.3.2 500 kV XLPE cable system: supply capability and experience...................................... 17 1.3.3 Choice of installation technology ................................................................................... 18 1.3.4 500 kV Study Project size............................................................................................... 19 1.3.5 Project specific requirements .......................................................................................... 19 1.3.6 Low ambient temperatures.............................................................................................. 20 1.3.7 Proving the performance of the cable system before it is supplied ................................ 21 1.4 Estimates of reliability ............................................................................................................ 22 1.5 Estimates of capital cost.......................................................................................................... 24 1.5.1 Scenarios considered for costing..................................................................................... 26 1.5.2 Estimated capital cost: comparison between scenarios................................................... 28 1.5.3 Estimated Net Present Value: comparison between scenarios........................................ 29 1.5.1 Summary of cost estimates ............................................................................................. 30 1.5.2 Cost differences between cable and overhead line ......................................................... 31 1.6 500 kV Study Project duration................................................................................................ 32 1.7 Power losses............................................................................................................................ 33 1.7.1 Relationship of power loss to power transfer for the 500 kV Study Project .................. 34 1.7.2 Cumulative power losses for the 500 kV Study Project ................................................. 36 1.7.3 Estimated NPV of cumulative power losses ................................................................... 37 1.8 Recommendations for next steps ............................................................................................ 38 1.8.1 Study of end to end reliability and availability ............................................................... 39 1.8.2 System and design studies............................................................................................... 39 1.8.3 Carry out additional engineering studies, as required..................................................... 39 2 REQUIREMENTS FOR UNDERGROUND POWER TRANSMISSION SYSTEM FOR THE 500 KV STUDY PROJECT.................................................................................................................... 44 2.1 Functional requirement: .......................................................................................................... 44 2.1.1 Functional requirement: power transmission.................................................................. 44 2.1.1 Functional requirement: ambient temperatures............................................................... 46 2.2 Scenarios considered............................................................................................................... 48 3 BASIC DESCRIPTION OF 500 KV AC UNDERGROUND TECHNOLOGY ........................... 56 3.1 Alternating current transmission system................................................................................. 56 3.2 Voltage, current and power..................................................................................................... 56 3.2.1 Voltage ............................................................................................................................ 56 3.2.2 Power .............................................................................................................................. 58 3.2.3 Current ............................................................................................................................ 58

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3.3 Component parts of the cable.................................................................................................. 59 3.4 Cable system ........................................................................................................................... 61 3.4.1 Component parts of the cable system ............................................................................. 65 3.4.2 Cable spans ..................................................................................................................... 65 3.4.3 Cable Terminations ......................................................................................................... 66 3.4.4 Cable Joints ..................................................................................................................... 68 3.4.5 Bonding equipment. ........................................................................................................ 69 3.5 Ancillary equipment................................................................................................................ 71 3.6 Hydraulic system for SCFF cable systems only ..................................................................... 72 3.7 Thermal design........................................................................................................................ 72 3.8 Thermomechanical design ...................................................................................................... 72 3.9 Installation design ................................................................................................................... 73 3.9.1 Cable installation............................................................................................................. 73 3.9.2 Assembly of joints and terminations............................................................................... 76 3.10 Route protection and identification......................................................................................... 78 3.11 Forced cooling......................................................................................................................... 79 3.12 Operation, maintenance and repair ......................................................................................... 81 3.13 Testing..................................................................................................................................... 81 3.13.1 Proving tests.................................................................................................................... 82 3.13.2 Quality tests..................................................................................................................... 85 3.14 Permissible length of an AC underground cable circuit ......................................................... 87 4 STATE OF THE ART FOR 500 KV UNDERGROUND POWER TRANSMISSION ................ 90 4.1 Introduction............................................................................................................................. 90 4.2 Self-Contained Fluid Filled Cables (SCFF)............................................................................ 91 4.3 Cross-Linked Polyethylene Cable (XLPE) ............................................................................. 94 4.4 Advantages of extruded cross-linked polyethylene cables ..................................................... 96 4.4.1 XLPE cable has the advantage over the SCFF type of : ................................................. 96 4.4.2 XLPE cable technology .................................................................................................. 97 4.5 Accessories for XLPE cable systems...................................................................................... 98 4.6 Cumulative service experience of XLPE cable systems ....................................................... 105 4.7 Electrical tests for XLPE cable systems ............................................................................... 111 4.7.1 Importance of prequalification tests for EHV XLPE cables......................................... 112 4.7.2 Prequalification test recommendations for the 500 kV Study Project .......................... 113 4.8 Low temperature operation ................................................................................................... 115 4.8.1 Ambient temperature levels for the Edmonton region of Alberta ................................ 115 4.8.2 Low temperature risks................................................................................................... 118 4.9 Types of cable installation .................................................................................................... 123 4.9.1 Direct Buried Installation.............................................................................................. 123 4.9.2 Duct-manhole system.................................................................................................... 126 4.9.3 Tunnel Installation ........................................................................................................ 128 4.9.4 Service experience with different methods of installation at 400 kV and 500 kV ....... 129 4.9.5 Service experience with forced cooled systems............................................................ 130

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4.10 Gas insulated lines ................................................................................................................ 130 4.10.1 Description of GIL ........................................................................................................ 131 4.10.2 GIL Experience ............................................................................................................. 134 4.10.3 GIL: Advantages and Disadvantages ............................................................................ 136 4.11 High Temperature Superconducting Cable........................................................................... 137 4.11.1 Superconductivity ......................................................................................................... 137 4.11.2 Low temperature superconductors ................................................................................ 138 4.11.3 High temperature superconductors ............................................................................... 139 4.11.4 Construction of a conceptual HTSC cable.................................................................... 140 4.11.5 HTSC Cable System Experience .................................................................................. 144 4.11.6 Installation of a conceptual HTSC cable system for the Study project ........................ 147 5 ESTIMATES OF RELIABILITY................................................................................................. 152 5.1 Repair times for 500 kV XLPE cable ................................................................................... 153 5.2 Fault statistics for underground 500 kV XLPE cable ........................................................... 153 5.2.1 Cable system fault statistics .......................................................................................... 153 5.2.2 Application of fault statistics to the 500 kV Study Project scenarios........................... 155 5.2.3 500 kV Study Project fault rate..................................................................................... 159 5.2.4 Types of cable faults ..................................................................................................... 159 5.3 Overhead line fault statistics ................................................................................................. 160 6 OVERVIEW OF POTENTIAL ENVIRONMENTAL EFFECTS OF UNDERGROUNDING.. 161 7 PRELIMINARY 500 KV UNDERGROUND CABLE SCOPING STUDY ............................... 163 7.1 Description of the cable type used for the preliminary scoping study.................................. 163 7.2 Cable installation options...................................................................................................... 166 7.3 General installation configuration......................................................................................... 167 7.4 Preliminary scoping study: duct-manhole system ................................................................ 169 7.4.1 Configuration of cables in ducts ................................................................................... 169 7.4.2 Duct for scoping study .................................................................................................. 170 7.4.3 Trench filling................................................................................................................. 171 7.5 Preliminary scoping study: Cable installation direct in the ground ...................................... 172 7.6 Minimum spacing between groups of cables of each circuit ................................................ 175 7.7 Installation Swathe and spacing between circuits,.............................................................. 176 7.8 Sample ampacity calculation (XLPE cable) ......................................................................... 178 7.9 Stabilised backfill.................................................................................................................. 180 7.10 Effect of obstructions on the route ........................................................................................ 181 7.10.1 Methods of maintaining the ampacity where the cable depth must be increased. ........ 181 7.10.2 Installation at increased phase spacing. ........................................................................ 181 7.10.3 Installation in tunnels. ................................................................................................... 184 7.10.4 Further methods of obstruction crossing....................................................................... 185 7.11 Cable lengths between joint bays.......................................................................................... 186 7.11.1 Outline reel dimensions ................................................................................................ 186 7.11.2 Cable reel transportation study ..................................................................................... 188 7.12 Manholes and joint bays ....................................................................................................... 188

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7.13 Tunnels.................................................................................................................................. 190 7.13.1 Tunnel ampacity............................................................................................................ 190 7.13.2 Cable installation in tunnels.......................................................................................... 191 7.13.3 Tunnel cross sections .................................................................................................... 192 7.14 Staging of the cable installation ............................................................................................ 194 7.15 Staged duct manhole cable installation................................................................................. 196 7.15.1 Installation layout.......................................................................................................... 196 7.15.2 Reasons for proposal..................................................................................................... 197 7.16 Staged cable installation direct in the ground ....................................................................... 198 7.16.1 Installation layout.......................................................................................................... 198 7.16.2 Reasons for proposal..................................................................................................... 199 7.17 Staged cable installation in deep tunnel................................................................................ 199 7.17.1 Installation layout.......................................................................................................... 200 7.17.2 Reasons for proposal..................................................................................................... 200 7.18 Staged cable installation in cut and cover tunnel.................................................................. 200 7.18.1 Installation layout.......................................................................................................... 201 7.18.2 Reasons ......................................................................................................................... 202 7.19 Alternative staging arrangements.......................................................................................... 202 7.20 Alternative SCFF cable type for scoping study .................................................................... 203 7.20.1 SCFF cable power losses .............................................................................................. 205 7.20.2 SCFF LPP cable installation configuration................................................................... 205 7.21 Cable system routine maintenance........................................................................................ 207 7.21.1 Maintenance for 500 kV XLPE cable systems ............................................................. 207 7.21.2 Recommended routine maintenance on 500 kV SCFF cable systems.......................... 210 7.22 500 kV cable system spares and repairs................................................................................ 211 8 ELECTROMAGNETIC FIELD PROFILE .................................................................................. 213 9 DESIGNS PROPOSALS FROM PROSPECTIVE SUPPLIERS: SYSTEM DESIGN ............... 215 9.1 Inquiry and questionnaire documents ................................................................................... 215 9.1.1 Inquiry document .......................................................................................................... 215 9.2 Requests for technical information from prospective suppliers of 500 kV cable systems ... 216 9.3 System designs proposed by prospective suppliers .............................................................. 219 9.3.1 Duct-Manhole systems.................................................................................................. 222 9.3.2 Direct buried systems.................................................................................................... 222 9.3.3 Tunnel systems.............................................................................................................. 222 9.3.4 Sheath bonding systems ................................................................................................ 222 9.4 Designs proposals from prospective suppliers: cable ........................................................... 223 9.4.1 XLPE cable designs: general ........................................................................................ 224 9.4.2 Conductors for XLPE cable designs ............................................................................. 224 9.4.3 Core design for XLPE cable designs ............................................................................ 224 9.4.4 Sheath design for XLPE cable designs ......................................................................... 224 9.4.5 Distributed Temperature Sensing.................................................................................. 225 9.4.6 Jacket design for XLPE cable designs .......................................................................... 226

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9.4.7 SCFF cable designs....................................................................................................... 226 9.4.8 GIL design..................................................................................................................... 226 9.4.9 Cable design types proposed......................................................................................... 227 9.5 Cable electrical values provided by suppliers....................................................................... 237 9.6 Splice designs proposed by prospective suppliers ................................................................ 238 10 TRANSITION STATION......................................................................................................... 240 11 POWER LOSSES ..................................................................................................................... 242 11.1.1 Relationship of power loss to power transfer for the 500 kV Study Project ................ 242 11.1.2 Cumulative power losses for the 500 kV Study Project ............................................... 244 11.1.3 Estimated Net Present Value of Losses ........................................................................ 246 12 GENERIC COST STUDY FOR THE 500KV STUDY PROJECT ......................................... 248 12.1 Cable system unit costs ......................................................................................................... 248 12.2 End-to-end estimated capital costs for the 65 km route length............................................. 249 12.3 Capital cost estimates: comparison of components in each scenario.................................... 250 12.4 Estimated Net Present Value of the life cycle costs for the 65 km route length................... 255 12.5 Comparison of the cost of each scenario ............................................................................ 256 12.6 Differences between the estimated cost of underground cable and overhead line ............... 257 12.7 Sensitivity studies on the estimated capital cost of the cable system ................................... 261 12.7.1 Sensitivity: Effect on cost of SCFF cable ..................................................................... 261 12.7.2 Sensitivity: Canadian Dollar value falls against other currencies by 20% ................. 261 12.7.3 Sensitivity: Metal prices change by 50%...................................................................... 263 13 500 kV STUDY PROJECT DURATION................................................................................. 265 13.1 Cable ..................................................................................................................................... 266 13.2 Transition station................................................................................................................... 266 14 UNDERGROUNDING THE ENTIRE 65 KM ROUTE LENGTH......................................... 267 14.1 Scenarios considered............................................................................................................. 267 14.2 Technical limitations............................................................................................................. 267 14.2.1 Voltage control.............................................................................................................. 267 14.2.2 Reduction in useful power transmission capacity because of cable charging current .. 267 14.3 Supplier capability ................................................................................................................ 268 14.4 Cost estimates ....................................................................................................................... 269 14.5 Cable system fault statistics for 65 km underground route length........................................ 269 15 500 kV STUDY PROJECT RISKS .......................................................................................... 271 15.1 Technical risks ...................................................................................................................... 271 15.1.1 Inability of the accessories to meet the required minimum winter design temperatures. 271 Remedial Action: .......................................................................................................................... 271 15.1.2 Uncertainty of the winter minimum design temperature .............................................. 271 15.1.3 Failure of the joints to demonstrate reliability in the Proving Tests............................. 272 15.1.4 Failure of the cable system to achieve reliable service performance............................ 272 15.1.5 Inability to repair the circuit at winter minimum ambient temperature:....................... 273 15.2 Contractual risks ................................................................................................................... 274

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15.2.1 Failure to attribute responsibility: ................................................................................. 274 15.3 Schedule risks ....................................................................................................................... 274 15.3.1 Delayed development:................................................................................................... 274 15.3.2 Delayed manufacture: ................................................................................................... 275 15.3.3 Delayed installation and commissioning: ..................................................................... 275 15.3.4 Damage to cable during delivery or installation ........................................................... 276 15.3.5 Commissioning test failure and repair .......................................................................... 277 15.4 Common mode failure .......................................................................................................... 278 15.4.1 Repeated latent defect in manufactured cable or accessories ....................................... 278 15.4.2 Repeated jointing error.................................................................................................. 279 15.4.3 Third party damage. ...................................................................................................... 279 15.4.4 Fire in tunnel. ................................................................................................................ 280 15.5 Collateral Damage................................................................................................................. 280 15.5.1 Failure of one cable causes damage to another............................................................. 280 15.5.2 Failure of one joint causes damage to another.............................................................. 281 15.5.3 Failure of one termination causes damage to another................................................... 281 15.5.4 Testing of one cable system causes damage to another ................................................ 281 15.5.5 Repair of one cable causes damage to another ............................................................. 282 15.6 Cost risks............................................................................................................................... 282 16 DEFINITIONS AND GLOSSARY .......................................................................................... 284 FEASIBILITY STUDY REFERENCES .............................................................................................. 299 APPENDICES ...................................................................................................................................... 304 1 Appendix: Overhead line performance and statistics ................................................................... 304 2 Appendix : Total capital cost estimate for each scenario.............................................................. 304 3 Appendix : Economic comparison of scenarios for the 500 kV underground cable feasibility report 304 4 Appendix: Project schedule .......................................................................................................... 304 5 Appendix: System study (reactor requirements, voltage profiles and losses) .............................. 305 6 Appendix: Generic crossings route maps: East TUC.................................................................... 305 7 Appendix: Generic crossings route maps: West TUC .................................................................. 306 8 Appendix: Transmission System Requirements ........................................................................... 306 9 Appendix: Analysis of the minimum winter temperatures recorded on the 240kV DESS circuit in Edmonton in 2009................................................................................................................................. 306 10 Appendix: The Damage Prevention Process In Alberta ........................................................... 306 11 Appendix: Potential overview of environmental effects of undergrounding............................ 307 12 Appendix: Cable reel transportation study of feasibility and costs .......................................... 307 13 Appendix: Magnetic fields for cable and overhead line ........................................................... 307 14 AESO introduction letter for CCI ............................................................................................ 307 15 500kV Heartland inquiry .......................................................................................................... 307 16 Appendix: 500kV Heartland transmission project response template ...................................... 308 17 Appendix : AIS transition station scope of work...................................................................... 308 18 Appendix: Heartland underground construction: construction overview ................................. 308

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19 20 21 22 23 24 25 26

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Appendix : Heartland underground line-civil estimate............................................................. 308 Appendix: ‘Heartland underground crossing requirements’..................................................... 309 Appendix : Heartland overhead line scope of work.................................................................. 309 Appendix : Substation 1 scope of work .................................................................................... 309 Appendix : Substation 2 scope of work .................................................................................... 309 Appendix: Owners risk briefing................................................................................................ 310 Appendix: Overhead and underground line maintenance......................................................... 310 Appendix: Drawings of termination stations, cable trenches, and obstruction crossings......... 310

TABLE OF FIGURES Figure 1. 500 kV Study project – estimated capital cost main components ........................................... 25 Figure 2 Comparison of scenario trench cross sections.......................................................................... 27 Figure 3. Estimated capital costs in 2009 dollars.................................................................................... 29 Figure 4 Estimated NPV of the life cycle costs for each scenario .......................................................... 30 Figure 5. Power losses for selected scenarios at different levels of transmitted power.......................... 35 Figure 6. Overhead line: Normal operation ............................................................................................ 45 Figure 7. Overhead line: Contingency operation .................................................................................... 46 Figure 8 Comparison of scenario trench cross sections.......................................................................... 50 Figure 9 Scenario 1A.10 and 1B.20........................................................................................................ 52 Figure 10 Scenario 2A.10 and 2B.20...................................................................................................... 52 Figure 11 Scenario 3A.10 and 3B.20...................................................................................................... 53 Figure 12 Scenario 4A.10 and 4B.20...................................................................................................... 53 Figure 13 Scenario 5A.65 ....................................................................................................................... 54 Figure 14 Scenario 5B.65........................................................................................................................ 54 Figure 15 Scenario 6 : No cable.............................................................................................................. 55 Figure 16 Key to scenario diagrams ....................................................................................................... 55 Figure 17. Three parallel lines or cables are required to form an AC circuit ......................................... 56 Figure 18. Relative voltages of a 500 kV system ................................................................................... 57 Figure 19. Voltages between individual 500 kV cables.......................................................................... 57 Figure 20. Voltage across the insulation of a 500 kV cable ................................................................... 58 Figure 21. Component parts of a 500 kV XLPE cable ........................................................................... 59 Figure 22. The component parts of a cable system................................................................................. 61 Figure 23. Two circuits comprising four groups of underground cables................................................ 62 Figure 24. 400 kV transition station with terminal gantry..................................................................... 63 Figure 25. 400 kV transition station with terminal tower ....................................................................... 64 Figure 26. Two overhead line circuits connect to four groups of underground cable ............................ 64 Figure 27. Delivery with cable reel axle cross-wise ............................................................................... 65 Figure 28. Delivery with cable reel axle length-wise ............................................................................. 65 Figure 29. Loading cable reels in ship’s hold ......................................................................................... 66 Figure 30. Outdoor cable terminations ................................................................................................... 67

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Figure 31, Cable terminations into gas immersed switchgear ................................................................ 68 Figure 32. A joint on a 400 kV XLPE cable prepared for burial ............................................................ 69 Figure 33. Part assembly of a joint on 240 kV XLPE cable inside a vault in Edmonton ....................... 69 Figure 34. An above-ground link box housing the components for a cross bonded position................. 70 Figure 35. Above ground link kiosks connected to 400 kV underground cable..................................... 71 Figure 36. Duct-manhole cable installation ............................................................................................ 73 Figure 37. Direct buried cable installation.............................................................................................. 74 Figure 38. Typical formations for cables installed in ducts.................................................................... 74 Figure 39. Typical formations for direct-buried cables .......................................................................... 75 Figure 40. Preparation of cable trench crossing agricultural land .......................................................... 75 Figure 41. Jointing in progress in clean conditions ................................................................................ 77 Figure 42. Completed joints.................................................................................................................... 77 Figure 43. Temporary cable termination assembly structure.................................................................. 78 Figure 44: 400 kV cable system being prepared..................................................................................... 83 Figure 45: A Cable being prepared for type approval ............................................................................ 83 Figure 46. High voltage AC commissioning test equipment .................................................................. 86 Figure 47. Three reactors located in a substation.................................................................................... 87 Figure 48. SCFF 525 kV 1,000 mm2 cable commissioned in Grand Coulee Dam in 1976.................... 92 Figure 49. SCFF LPP 2,500 mm2 cable, similar to that commissioned in Japan in 1994 ...................... 93 Figure 50. 500 kV XLPE cable ............................................................................................................... 94 Figure 51. Increase of cable shield stresses at higher transmission voltages.......................................... 95 Figure 52. Chart of XLPE cable design stress with system voltage. ...................................................... 99 Figure 53. Extrusion moulded joint (EMJ) schematic ............................................................................ 99 Figure 54. 500 kV XLPE cable and extrusion moulded joints in a tunnel .......................................... 100 Figure 55. One-piece joint (OPJ) schematic ......................................................................................... 101 Figure 56. 275 kV EPR OPJ in manufacture ........................................................................................ 101 Figure 57. 400 kV silicone OPJ in manufacture and routine test ........................................................ 102 Figure 58. Prefabricated composite joint (PJ) schematic...................................................................... 103 Figure 59. Prefabricated composite joint (PJ) during assembly ........................................................... 103 Figure 60. 500 kV PJ joints on test ....................................................................................................... 105 Figure 61, Outdoor termination with capacitor stress control .............................................................. 120 Figure 62. Outdoor termination with prefabricated composite, premoulded stress cone ..................... 121 Figure 63. Typical direct buried 400kV cable trench containing one Group of Cables ....................... 124 Figure 64. Component parts of a 400 kV gas insulated line ................................................................. 131 Figure 65. Two groups of 275 kV gas insulated line installed in a tunnel........................................... 134 Figure 66. One group of 400 kV gas insulated line installed on stilts in a substation .......................... 134 Figure 67. Cross section of a conceptual HTSC cable.......................................................................... 141 Figure 68. 13 kV, three phase, concentric HTSC cable construction ................................................... 144 Figure 69. Conceptual arrangement of an HTS cable in buried trough ................................................ 149 Figure 70. Conceptual cross section dimensions of a HTSC buried, three phase group / trench arrangement .................................................................................................................................... 150 Figure 71. Conceptual installation swathe dimensions for a HTS cable trenches ................................ 151

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Figure 72: Construction and dimensions of Scoping Study 500 kV, 2500 mm², XLPE cable............. 164 Figure 73 Scenario 1 ............................................................................................................................. 167 Figure 74: Preliminary duct block arrangement ................................................................................... 169 Figure 75: Preliminary direct burial arrangement................................................................................. 172 Figure 76: Trench with sloped sides ..................................................................................................... 174 Figure 77: Spacing between Groups of Cables ..................................................................................... 176 Figure 78: Arrangement of circuits and construction Swathe.............................................................. 177 Figure 79: Photograph of construction swathe for four trenches.......................................................... 178 Figure 80: Sample ampacity calculation ............................................................................................... 179 Figure 81: Required phase spacing at increased laying depth .............................................................. 182 Figure 82: Requirement for cable installed by trenchless method........................................................ 183 Figure 83: Typical directional drill arrangement, plan view ................................................................ 183 Figure 84: Typical naturally ventilated tunnel ...................................................................................... 184 Figure 85: Compound containing two headhouses for naturally ventilated tunnels............................. 185 Figure 86: Typical reel dimensions and weight .................................................................................... 186 Figure 87: Conventional delivery ......................................................................................................... 187 Figure 88: Longitudinal reel on lowboy ............................................................................................... 187 Figure 89: Plan of typical joint bay....................................................................................................... 188 Figure 90: Longitudinal elevation of typical joint bay ......................................................................... 189 Figure 91: Elevation cross section across typical joint bay .................................................................. 189 Figure 92:Tunnel temperatures over a 10 year period .......................................................................... 191 Figure 93: Typical tunnel cable clamp (cleat) for a sagged system...................................................... 192 Figure 94:Tunnel cross section: deep tunnel......................................................................................... 193 Figure 95:Tunnel cross section: cut and cover...................................................................................... 193 Figure 96 Scenario 2, one group per circuit installed initially (black), the second later ...................... 194 Figure 97: Staging summary ................................................................................................................. 195 Figure 98: Scenario 2, staging for the duct-manhole system................................................................ 196 Figure 99:Scenario 2, staging for cables direct buried in the ground ................................................... 198 Figure 100: Scenario 2, staging for cables installed in deep tunnels .................................................... 199 Figure 101: Scenario 2, staging for cables installed in cut and cover tunnels ...................................... 201 Figure 102: Alternative SCFF 500 kV cable ........................................................................................ 204 Figure 103. Underground cable: design requirement............................................................................ 220 Figure 104 Cable spacing...................................................................................................................... 221 Figure 105. Cross bonding schematic ................................................................................................... 223 Figure 106. Detail of cross bonding components ................................................................................. 223 Figure 107: Proposed 500 kV design: extruded lead sheath ................................................................. 228 Figure 108: Proposed 500 kV design: welded aluminium sheath......................................................... 229 Figure 109: Proposed 500 kV design: corrugated aluminium sheath ................................................... 230 Figure 110: Proposed 500 kV design: copper wire screen and corrugated stainless steel sheath......... 231 Figure 111: Proposed 500 kV design: copper wire screen and lead sheath.......................................... 232 Figure 112: Proposed 500 kV design: wire screen and smooth aluminium sheath .............................. 233 Figure 113: Proposed 500 kV design: copper wire screen and aluminium laminate............................ 234

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Figure 114: Proposed 500 kV design: self contained fluid filled ......................................................... 235 Figure 115: Proposed 500 kV design: GIL ........................................................................................... 236 Figure 116 One piece prefabricated joint (OPJ) ................................................................................... 239 Figure 117. Prefabricated composite joint (PJ)..................................................................................... 239 Figure 118. Indoor GIS switchgear....................................................................................................... 240 Figure 119. Power losses for selected scenarios at different levels of transmitted power.................... 243 Figure 120. Power losses for an average load of 457.3 MW ................................................................ 245 Figure 121. Estimated capital cost components in $M for 4 groups of Cables, 10 km long ................ 251 Figure 122. Estimated capital cost components in $M for 3 groups of Cables, 10 km long ................ 252 Figure 123. Estimated capital cost components in $M for 4 groups of Cables, 20 km long ................ 253 Figure 124. Estimated capital cost components in $M for 3 groups of Cables, 20 km long ................ 254 Figure 125. Estimated capital cost components in $M for all overhead line (Scenario 6) ................... 255 Figure 126. Historic variation in the value of Canadian dollar............................................................. 262 Figure 127. Historic variation in copper price (USD) .......................................................................... 264

TABLES Table 1. Description of Scenarios ........................................................................................................... 26 Table 2. Table of Scenarios..................................................................................................................... 27 Table 3. 500 kV Study Project costs, cost differences and cost ratios compared to all-overhead line... 31 Table 4. Ratio of cost of underground cable and transition stations to an equal length of overhead line .......................................................................................................................................................... 32 Table 5. Duration of cable supply and installation for each scenario ..................................................... 33 Table 6. Power losses for each scenario at an average load of 457.3 MW............................................. 36 Table 7. Power losses per circuit for each scenario at an average load of 1,000 MW ........................... 37 Table 8. PV of losses and of revenue requirement ................................................................................. 38 Table 9. Number of suppliers for each undergrounding scenario........................................................... 43 Table 10. Minimum design temperatures for cable ................................................................................ 47 Table 11. Minimum design temperatures for splices (joints) ................................................................. 47 Table 12. Maximum and minimum design temperatures for air insulated terminations ........................ 48 Table 13. Maximum and minimum design temperatures for gas insulated terminations ....................... 48 Table 14. Scenarios considered............................................................................................................... 51 Table 15 Cumulative quantities of underground cables of all types in each country ........................... 106 Table 16 Commercial applications of large conductor XLPE cable with joints by voltage, conductors size, and circuit length ................................................................................................. 109 Table 17 Summary of the cumulative lengths at each voltage of major XLPE circuits with large conductors, long lengths and joints ............................................................................................... 109 Table 18 XLPE Cable system component statistics: 315 kV to 500 kV............................................... 110 Table 19 SCFF Cable system component statistics: 315 kV to 500 kV ............................................... 110 Table 20 Total cable system components installed up to end 2005: 315 kV to 500 kV....................... 111 Table 21 Comparison of statistics of XLPE circuit from three sources................................................ 111

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Table 22 EHV installation types, three phase cable lengths and number of projects ........................... 129 Table 23. Details of significant GIL applications ................................................................................. 135 Table 24. Details of some HTSC cables and applications .................................................................... 147 Table 25 CIGRE failure rates of components in 220 kV to 500 kV XLPE cable systems................... 154 Table 26 Failure rates of components in 220 kV to 500 kV XLPE cable systems by cause ................ 155 Table 27 Conditioned failure rates of components in 220 kV to 500 kV XLPE cable systems ........... 156 Table 28 Unconditioned cable system failure rates for the study scenarios for one year in-service .... 156 Table 29 Conditioned cable system failure rates for the study scenarios for one year in-service ........ 157 Table 30 Unconditioned cable system failure rates for the study scenarios for 40 years in-service .... 158 Table 31 Conditioned cable system failure rates the study scenarios for 40 years in-service .............. 158 Table 32 Numbers of faults in all types of 220 kV-500 kV AC land circuits by installation type....... 159 Table 33 OHL failure rates for the study scenarios for one year in-service ......................................... 160 Table 34 OHL failure rates for the study scenarios for forty years in-service...................................... 160 Table 35 Tunnel dimensions for scoping study .................................................................................... 190 Table 36. Magnetic field from EMF report (Appendix, Section 13) .................................................... 213 Table 37 Supplier responses: Average capacitance and dielectric losses for XLPE cable................... 237 Table 38 Supplier responses: Average capacitance and dielectric losses for SCFF cable ................... 237 Table 39 Supplier responses: Average capacitance for GIL................................................................. 237 Table 40 Combined conductor and sheath losses: XLPE cable – mean and maximum ....................... 238 Table 41 Conductor and enclosure losses of GIL ................................................................................. 238 Table 42. Power losses for each scenario at an average load of 457.3 MW......................................... 245 Table 43. Power losses per circuit for each scenario at an average load of 1,000 MW ....................... 246 Table 44. Estimated NPV of power losses over a forty year period. .................................................... 247 Table 45. Capital cost estimates for each scenario (2009 dollars)........................................................ 250 Table 46. Estimated NPV of the life cycle cost for each scenario........................................................ 256 Table 47. Effect on estimated cost of number of Groups of Cables ..................................................... 257 Table 48. Effect on estimated cost of staging ....................................................................................... 257 Table 49. 500 kV Study Project Estimated costs, cost differences and cost ratios compared to alloverhead line .................................................................................................................................. 258 Table 50. Ratio of estimated installed cost of underground cable to an equal length of overhead line 259 Table 51. Ratio of estimated cost of underground cable and transition stations to an equal length of overhead line .................................................................................................................................. 259 Table 52. Estimated capital cost increase if SCFF cable is used .......................................................... 261 Table 53. Estimated capital cost change if Canadian dollar value should vary by 20% ...................... 263 Table 54. Estimated capital cost change if cable metal prices should vary by 50%............................. 264 Table 55. Duration of cable supply and installation for each scenario ................................................. 265 Table 56 Unconditioned failure rates for a 65 km cable route length for one year in-service ............. 269 Table 57 Conditioned failure rates for a 65 km cable route length for one year in-service ................. 270 Table 58 Unconditioned failure rates for a 65 km cable route length for forty years in-service .......... 270 Table 59 Conditioned failure rates for a 65 km cable route length for forty years in-service .............. 270

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1 1.1

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EXECUTIVE SUMMARY Introduction

CCI has been engaged to perform a study into the feasibility of using 500 kV underground cable for a transmission system in the Edmonton region of Alberta. The example used for the 500 kV Study Project is generic and based on the two 3,000 MVA circuits known as the Heartland Project, with the understanding that the findings could be applied to other 500 kV transmission applications in the Edmonton region of Alberta. This report does not include an economic optimisation of the design as this would be performed at some future stage should it be decided to proceed with an underground option. The scope of the feasibility study also includes the identification of the next steps to be taken if it is decided to proceed with a detailed evaluation of an option that includes underground cable. While the AESO and others have provided information to CCI relevant to the study, the findings and recommendations are those of CCI alone. The main issues that have been addressed are: 

Technical feasibility of 500 kV underground cable systems This is summarised in Section 1.3 and is discussed in Sections 4, 7 and 9.



Reliability Reliability of the 500 kV cable system is summarised in Section 1.4 and is discussed within Section 5.2.1. Reliability of the 500 kV overhead line systems is discussed within Section 5.3 and information is given in Appendix, Section 1.



Estimated costs These are summarised in Section 1.5 and is discussed in Section 12, with detailed information being given in the Appendices, Sections 2 and 3.



500 kV Study Project schedule This is summarised in Section 1.6 and is discussed in Section 13, with detailed information being given in Appendix, Section 4.



Power losses This is summarised in Section 1.7 and discussed in Section 11, with detailed information being given in Appendix, Section 5.

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1.2

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

Recommendations for next steps These are summarised in Section 1.8.



500kV Study Project risks These are discussed in Section 15.

Method of approach

This report is based on the prospective requirement to use underground cable for all or part of two 500 kV Transmission circuits in the Edmonton region of Alberta. This is referred to as the 500 kV Study Project. The example upon which the design parameters and the terrain of the route of the 500 kV Study Project have been based is the proposed Heartland Project, which consists of two parallel 500 kV, 3,000 MVA circuits with a route length of 65 km per circuit. A summary of the division and sequence of work between CCI, HPT and AESO is given below: CCI



 

 

Performed a scoping study as the basis for :  Invitation to cable suppliers to provide outline designs, budgetary costs and manufacturing times.  Outline trench cross-section dimensions to be provided to HPT for a) normal installation conditions and b) for special construction at a generic obstruction crossing. Participated in visits to Tokyo with AESO and HPT to evaluate a) the only operational, long length 500 kV cable system in the world and b) the premises of two of the manufacturers who supplied it. Analysed the manufacturers’ design responses to provide averaged:  Cable sizes.  Installation layouts.  Manufacturing and jointing times.  Estimated capital costs of cable, accessories and spares; these were normalised to allow for common metal prices and exchange rates.  Cable system energy losses. Reviewed the state of the art of cable technology with respect to the 500 kV Study Project. Advised:  Feasibility of the available cable technologies to the 500 kV Study Project.  Risks associated with 500 kV cable technology for use in the Edmonton region of Alberta.  Next steps to be followed if an underground option is to be investigated further.

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HPT

   

AESO

   

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Selected preliminary routes for indicative civil and installation costing purposes, comprising installation of a) cable laying in normal conditions and b) cable crossings of route obstructions. Selected the installation type, i.e. that the cable should be direct buried in the ground. This being considered to be the lowest cost option. Compiled a project schedule. Compiled the total estimated capital costs of nine scenarios comprising a) different proportions of underground cable to overhead line and b) transition stations.

Studied the effect of the underground cable on the operation of the system. Studied the effect of reactive compensation on the operation of the transmission system containing underground cable. Compiled the lifecycle costs of nine different scenarios. Calculated the cost of losses of the cable, reactors and overhead line.

In order to obtain information for the 500 kV Study Project on the availability of 500 kV cable systems and the estimated costs for cable systems, a number of prospective manufacturers were contacted and technical proposals and budgetary prices were requested. The request was based on the requirements for the Heartland Project, with a generic underground route length of nominally 10 km. The ambient air and ground temperature information given to suppliers was based generally on the design parameters that had been used for the 240 kV Downtown Edmonton Supply and Substation (DESS) underground cable project. The estimated cost provided by each prospective cable supplier was given on the basis that, for commercial reasons, it would remain confidential. The estimated cost and design information have therefore been presented in this report a non attributable manner. A summary of the designs proposed by prospective suppliers is given in Section 9. Different scenarios, which each include some underground cable, were agreed for study; Figure 9, Figure 10, Figure 11 and Figure 12. Each scenario comprises different combinations of underground cable length, overhead line length and numbers of parallel Groups of Cables. These scenarios include options for undergrounding the following generic lengths in a nominal 65 km route:  

10 km underground cable (55 km overhead line) 20 km underground cable (45 km overhead line)

The estimated costs of the scenarios containing either a 10 km or 20 km length of underground cable were compared with the estimated cost of a 65 km all-overhead line scenario, with no underground cable. Some consideration was also given to the engineering implications of undergrounding the entire 65 km route, Section 14, although the costs were not estimated.

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To obtain representative costs for installation conditions, indicative routes in the Edmonton Transportation Utility Corridor (TUC) were chosen by the HPT. The lengths of these indicative routes do not necessarily correspond with the generic 10 km and 20 km lengths chosen for the study. These are shown in Appendix, Sections 6 and 7. The work by the HPT is acknowledged with thanks. Indicative installation designs were prepared by CCI so that the feasibility of undergrounding could be evaluated and to determine the civil cost and practicability. These were based on the ground conditions through which the cable system would have to be installed and the types of obstruction which would have to be crossed. Details of these indicative designs are given in Section 7. Information was collected and compiled for inclusion in this report by CCI from information supplied a) on the cable system by the cable manufacturers and b) on the type of civil works installation supplied by the HPT. The estimated costs given in this feasibility study were expected to be within a range of plus or minus thirty percent.

1.3

Technical feasibility findings

The conclusions are that:  Cable is technically feasible for the underground part of the 500 kV Study Project.  Cable with extruded, cross-linked polyethylene (XLPE) is the best choice of cable type. The proviso is that the performances of the particular 500 kV XLPE designs of cable and accessories to be offered by selected manufacturers must be validated on test as described in Section 1.3.7. Key tests are:  

Accelerated aging conditions at elevated voltage and high current loading for one year to IEC 62067[1] Simulated low ambient temperature for a representative period, this being a special requirement for this 500 kV Study Project.

The reasons for the choice of this technology and the need to demonstrate performance are given below.

1.3.1 

Choice of cable technology The most appropriate cable system technology for the 500 kV Study Project is cable insulated with extruded, cross-linked polyethylene (XLPE). XLPE cable has the benefits of:

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 

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Low energy loss. Solid insulation that does not require impregnation with insulating fluid and consequently a) risk of leakage into the environment is eliminated b) maintenance is reduced and c) risk of fire spread is reduced.

XLPE cable is preferred to the alternative pre-existing design of cable, which is the selfcontained fluid-filled (SCFF) type insulated with polypropylene paper laminate (LPP) tape. The numbers of applications and suppliers of SCFF cable are presently falling to a level where it is foreseen that it will soon become obsolete for land cable applications. The suitably trained and experienced personnel and specialist equipment which would be required for a SCFF cable system for the 500 kV Study Project will consequently become increasingly difficult to obtain. There are also environmental concerns regarding possible leakage of insulating fluid from SCFF cable systems. 

1.3.2

Other technologies of Gas Insulated Line (GIL) and High Temperature Superconducting (HTS) cable have also been evaluated. GIL is a possible alternative for a tunnel application, but is not recommended for a long length buried application. (No proposals for buried GIL systems have been received from any prospective suppliers.) GIL has the advantages of a high power carrying capacity and reduced need for reactive compensation. A long length GIL circuit contains large volumes of Sulphur Hexafluoride (SF6) insulating gas and there are some environmental concerns regarding possible leakage. HTS cable has not been sufficiently developed for use in a high power, long length application with joints, such as the 500 kV Study Project and so is not considered further.

500 kV XLPE cable system: supply capability and experience



The typical design of direct buried XLPE cable system proposed by prospective manufacturers to meet the requirement to transmit 3,000 MW comprised two cables per phase each having a copper conductor with a cross sectional area of 2,500 mm². This conductor size is at the top end of the range that has been installed to date. Conductor sizes of up to 3,500 mm² have been developed for 500 kV cable.



The majority of the prospective manufacturers who were contacted were willing to offer a 500 kV XLPE underground cable system for the Heartland Project. From a supplier perspective a 500 kV XLPE underground cable system is thus indicated to be technically feasible. The cables and joints are prospectively suitable for installation either in the ground (buried or in ducts), or in tunnels.



A fully tested and service proven ‘off the shelf’ design of 500 kV XLPE cable system (cables, accessories and ancillaries) does not exist for the 500 kV Study Project. Suitable designs of proven 500 kV XLPE cables and terminations exist, but the analysis of

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manufacturers’ responses shows that only a small number of commercially available, prefabricated, joints have commenced service experience at 500 kV. To date their initial service experience is judged to be insufficient to accept the designs as service proven for the substantially greater numbers required for the 500 kV Study Project. Some limited 500 kV test experience exists, but has not been sufficiently quantified by manufacturers. A utility in Shanghai[2] has awarded a major contract to two manufacturers for two 17 km long-length parallel circuits of 500 kV 2,500 mm² cable, which are at present at an advanced stage of construction in a tunnel. Two different types of 500 kV prefabricated joint are being installed. Other manufacturers’ submissions for the 500 kV Study Project indicated that similar designs of 500 kV joints exist, in the form of either prototype joints undergoing inhouse evaluation tests, or as design proposals. 

Three suppliers have commercial experience with the manufacture and installation of large conductor 500 kV cable and joints. There are many 400 kV cable systems in operation that contain XLPE insulated cables having the same 2,500 mm² conductor size that would be needed for the 500 kV Study Project. Many of these include the prefabricated joint types proposed for the 500 kV Study Project. However, the 400 kV cables and joints operate at a lower electrical stress than is required for the 500 kV Study Project. The existence of these 400 kV circuits is a good indicator that there are several more manufacturers who have the right level of capability and experience to develop, manufacture and install a long length, high power 500 kV cable system. It is normal for manufacturers to custom-design underground EHV transmission circuits for each particular application, including the necessary supporting development work and Proving Tests.

1.3.3

Choice of installation technology



The most appropriate cable installation technology for the 500 kV Study Project is direct buried, naturally cooled, in terms of simplicity and anticipated total costs. A forced cooled system is more complex than a naturally cooled cable system. Because of the need for planned or unplanned outages to maintain the cooling equipment, it is less likely to be available for service. A naturally cooled system has no cooling equipment.



Prospective cable system suppliers provided designs and cost estimates for cable systems suitable for installation in naturally cooled direct buried, naturally cooled duct-manhole and forced ventilated tunnel arrangements. The HPT have provided installation cost estimates for the direct buried, naturally cooled, method.



The layout proposed by most manufacturers comprised four trenches each containing one Group of Cables. This is shown in Figure 23 and with installation dimensions typically as

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shown in Figure 78. This arrangement consists of two circuits, each comprising two Groups of Cables. Each Group of Cables has three individual single core cables installed in one trench. For the purpose of this feasibility study a total of eleven layout scenarios was considered in varying levels of detail. The scenarios have either different lengths of underground cable, different numbers of Groups (trenches) and different phased installation time Stages. The scenarios are described in Section 2.2.

1.3.4

500 kV Study Project size



An underground cable system for the 500 kV Study Project would be one of the largest in the world to date. If the route length were to be 20 km, and if two circuits, each consisting of two Groups of Cable were to be selected, the quantities of cable would be equal to those in the only very long 500 kV circuit in commission to date (in Tokyo). The Tokyo tunnel circuit was supplied by four cable manufacturers and commissioned nine years ago. (Since the installation of the Tokyo project, there has been a consolidation in the number of Japanese cable makers from four to two). The quantities required for the 500 kV Study Project are within the supply capabilities of cable manufacturers.



This would be the first application of direct buried, long length, large conductor 500 kV XLPE cable.



The 500 kV Study Project has the combination of the highest system voltage of 500 kV and one of the highest power ratings of 3,000 MVA, which results in a large conductor area of 2,500 mm² and a large diameter cable. The large cable size poses challenges to the manufacture, delivery and installation of worthwhile drum lengths of cable and in particular to the designs and performance of the accessories (joints and terminations) required.

1.3.5   

Project specific requirements The location-specific requirements for the 500 kV Study Project are the crossing of route obstructions; such as wide roads, railroads, wetlands and many oil and gas pipelines. If a major obstruction is encountered in a particular future route, such as the North Saskatchewan River valley, which is deep and wide, a separate feasibility study would be required to select a suitable method of crossing. Low temperature operation (see below).

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1.3.6

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Low ambient temperatures



The winter air and ground temperatures that occur in the vicinity of Edmonton are lower than those previously reported for any other 400 kV and 500 kV applications of XLPE cable systems. Some manufacturers submitted their experience lists for transmission voltages of less than 400 kV. These showed that some long length, large conductor cable systems have been supplied into locations in which the minimum winter ambient temperature is possibly less than zero degrees Celsius. However, no evidence of recorded minimum ambient temperatures was provided. For the 500 kV Study Project cable system to be acceptable it is necessary to demonstrate the operational reliability at low temperature of the cables and accessories. The cable accessories are prospectively the most vulnerable, because the elastomeric insulation would be operating closer to the ‘glass transition’ temperature at which the properties of high elasticity, believed to be essential for reliable electrical performance, are lost.



Temperature records from the 240 kV DESS duct-manhole project in Edmonton, show that: 

240 kV elastomeric joints and XLPE cable installed at 1.3 m depth have been exposed to a winter ground temperature of -8oC. To give an adequate margin of safety for the 500 kV Study Project, design temperatures are recommended of: 500 kV joints in a direct buried installation: -15oC 500 kV joints in a duct-manhole installation: -20oC



240 kV outdoor terminations have been exposed to a temperature of -46oC. To give an adequate margin of safety for the 500 kV Study Project, the design temperature is recommended to be in line with Alberta practices for outdoor electrical equipment: 500 kV outdoor terminations in open air:

-50oC



To demonstrate suitability for winter operation it is recommended as mandatory that prospective manufacturers participate in a series of development activities to demonstrate the low temperature performance of their 500 kV XLPE cable system.



The winter design temperatures can be raised to higher and more acceptable temperatures at which more service and test experience exists. Joint temperatures could be raised by burial at greater depths, for example to a depth of 2.5 m, at which depth the minimum ground temperature may be above 0oC, thus allowing the design temperature to be raised to, say, -5oC. Cable termination temperatures can be increased by installation within a specially

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constructed and temperature controlled building. This should allow the minimum air temperature to be maintained above, say, 0oC and the design temperature to be raised to, say, -5oC. (It is recommended that these alternatives be investigated in the next steps) 

A consequence of installing the cable system at greater depths is that system ampacity is reduced under the limiting summer rating condition. To ensure that the cable at greater depth does not exceed its maximum design temperature in summer the following studies are recommended to be performed: 





1.3.7 

A cyclic ampacity calculation be performed to take advantage of the reduction in heat generation due to the hourly fluctuating nature of the load current, in place of the continuous ampacity calculation that was applied to the 500 kV Study Project to meet the 3,000 MW requirement. An investigation be performed to see if a more favourable ampacity can be calculated in summer by taking into account the temperature of the ground at the proposed increased depth of cable burial. The present ampacity calculation method assumed that all of the ground is at a constant temperature, similar to the temperature close to the ground surface. This is the conventional assumption used in ampacity calculations for cables at depths of approximately 1 metre; but may be pessimistic for the Edmonton region of Alberta where the temperature of the ground at greater depths is significantly lower than that near the surface during the summer period. An evaluation be performed on increasing the number of cables per phase from two to three to take advantage of the reduction of heat generation in each cable.

Proving the performance of the cable system before it is supplied Both long term prequalification tests and low temperature tests must be performed It is normal practice to require manufacturers to perform tests of proof on their systems before providing supplies to applications such as the 500 kV Study Project. The requirements for these tests are stated in international specifications[1] for cables. Some cable system users formulate their own additional tests of proof to cover any special requirements for a particular application.



It is recommended that the cable systems must pass the following proving tests before they are supplied to the 500 kV Study Project: 

Prequalification test: a one year test to demonstrate performance when the particular cable voltage, cable conductor and joints have not been previously prequalified.

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

1.4

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

Type test: a six week long series of high voltage laboratory tests to prove the suitability of the cable system design selected for the study project.



Special proving tests: tests to demonstrate the reliability of the cable systems at Edmonton cold winter temperatures. It is recommended that a specific series of tests be specified and performed.

Most of the manufacturers expressed an interest in supplying the 500 kV cable systems for this Project and in performing the necessary tests. Some manufacturers provided details of the 500 kV proving tests that they had already commenced or completed, or are planning, for 2,500 mm² conductor cables and joints. None have yet completed a full series of tests on the size of cable, type of joints and type of direct buried installation that would be used for the Study Project. This is not considered to be an obstacle to them performing the required 500 kV prequalification tests.

Estimates of reliability 

Expectations of reliability Utilities throughout the world are now purchasing XLPE cable systems at voltages up to the highest EHV levels, which demonstrates their confidence in the reliability of this technology.



Quality assurance and testing, care and maintenance The 500 kV underground cable system can be expected to give reliable service, subject to:  Successful completion of proving tests before supply.  Quality control test programs during manufacture and installation.  Protection of the cable system from third party damage throughout its service life. The objective in the design, Proving Testing, manufacturing and installation of a 500 kV cable system is to eliminate failures in-service. After site assembly, a commissioning test is performed with the objective of detecting failures due to installation damage, or incorrectly assembled components. A high AC voltage withstand test is applied for 60 minutes; this test is specified in IEC 62067[1]. Although not yet required by IEC specifications, it has become normal practice for utilities to specify that partial discharge measurements be performed at each joint and termination. This is a non-destructive test to ensure that no detectable incipient electrical activity is

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present. Any faults detected are repaired, or replaced, before the cable system is accepted into service. Statistics show that a significant proportion of cable failures are due to third party ‘dig-ins’. Adequate protection measures must be incorporated into the design of the installation. Adequate surveillance and maintenance must be conducted throughout the service life. The incidence of third party damage can then be expected to be low. 

Availability of the transmission line It is a requirement of the design of the 500 kV Study Project that n-1 redundancy exists, such that either of the two circuits can carry the peak load of 3,000 MW as a contingency operation in the event that the other circuit is unavailable. For this redundancy to be effective, the risk of coincident failures on parallel transmission lines must be low and the repair time short. This report gives the failure rates and repair times of the cable system, based on published data, so that a statistical analysis may be performed in the recommended next steps. The reliability assessment for the complete transmission system must be performed to include the other components, which include overhead lines, transition station components and substation termination components.



Repair times The average estimated time to repair the 500 kV XLPE cable system is 29 days, with a variation between minimum and maximum times of 14 days. This estimated time is based on data collected from a survey of 220 kV to 500 kV XLPE cable installations. This time includes an allowance of four days for delays resulting from the extremes of weather and ambient temperature expected to be encountered in the Edmonton region of Alberta.



Published failure rates Published failure rates exist [49], for XLPE cable systems for the voltage category 220 kV to 500 kV in which many installations exist at 220 kV, but few at 500 kV. Failure rates per year of operation are given for the cable per 100 circuit km of length and for the accessories per 100 items. The reliability of the underground portion of the 500 kV Study Project was estimated for the particular quantities of XLPE cable, joints and terminations in each scenario by applying these published failure rates. The numbers of failures increase with the circuit length. The suppliers of the failure data [49] have advised caution in the use of the calculated failure rates as the data set is recognised as being too small to give reliable information. For this

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reason a direct comparison with published failure rates for overhead lines has not been presented. For information purposes, the published overhead line failure rates for sustained outages [79] have been presented separately in Section 5.3. Based on the published data [49] the estimated numbers of faults per year that occur in the 500 kV Study Project are given below for different numbers of Groups of Cables.

One ‘Groups of Cables’ in operation: Two ‘Groups of Cables’ in operation: Three ‘Groups of Cables’ in operation: Four ‘Groups of Cables’ in operation:

10 km 0.04 to 0.05 0.08 to 0.11 0.13 to 0.16 0.17 to 0.21

20 km 0.08 to 0.10 0.17 to 0.21 0.25 to 0.31 0.33 to 0.42

faults per year faults per year faults per year faults per year

The above fault numbers include external damage (third party dig-ins, subsidence, etc). Approximately 25% of the faults reported were as a result of external dig-in damage. This demonstrates the importance of providing robust protection and surveillance systems for the underground cable in the 500 kV Study Project. The majority of internal failures were attributed to accessories. This demonstrates the importance of robust design, stringent Proving Tests, quality control in manufacture, a high level of jointer proficiency in their assembly and the use of stringent on-site after-laying tests and in-service monitoring. The above failure data only includes the cable system (cable, joints and terminations).

1.5

Estimates of capital cost

(Note: all costs in this report are in Canadian dollars, unless otherwise stated. All capital cost estimates are in 2009 dollars). The estimated capital cost for the underground part of the 500 kV Study Project has been derived from anticipated price level information from prospective suppliers of 500 kV XLPE cable together with estimates of the civil construction costs, which were supplied by the HPT. For the total route length of 65 km, the estimated costs also include the overhead line and the associated transmission equipment, such as sub-stations, transition stations and reactive compensation, where required as depicted diagrammatically in Figure 1.

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Substation

Overhead Line (OHL)

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Transition Station

Transition Station

Overhead Line (OHL)

Substation

Underground Cable System

65 km

Figure 1. 500 kV Study project – estimated capital cost main components For the purpose of costing, the components in Figure 1 include the following: 

Substations (two)

The equipment necessary for the new 500 kV Study Project transmission line additional to the existing substation equipment. This includes telecommunication equipment and other items as detailed in Appendix, Section 2. 

Overhead Line (OHL)

The construction of the, double circuit, 500 kV overhead line for the 500 kV Study Project including diversions of existing lines as detailed in Appendix, Section 2. 

Transition Stations (two)

The construction of the new 500 kV transition stations between the overhead line and underground cable. This includes telecommunication equipment, reactors, switchgear and other items as detailed in Appendix, Section 2. 

Cable system supply and install

The supply and installation of the new 500 kV underground cable system as detailed in Section 12.1.

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

Other project costs:     

1.5.1

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Owners costs Distributed cost: Contingency Engineering and Supervision (E&S) Allowance for funds used during Construction (AFUDC)

Scenarios considered for costing

Estimates were prepared for eight scenarios for undergrounding either 10 km or 20 km of the 65 km route, plus, for reference, an all-overhead line. The scenarios have (a) different proportions of underground cable and overhead line lengths, (b) different numbers of groups of cables in parallel and (c) different installation time stages in which not all of the Groups of Cables are installed initially. These are shown schematically in Section 2.2, Figure 9, Figure 10, Figure 11, Figure 12 and Figure 15 

Table 1 and Table 2 give descriptions of each of the scenarios.



Figure 2 gives a comparison of the cross section for each scenario, showing: The number of Groups of Cables. Whether they are installed in stage 1 or stage 2.

Scenario 1A.10 and 1B.20 2A.10 and 2B.20 3A.10 and 3B.20 4A.10 and 4B.20 6

Description 4 Groups of Cables (2 cables per phase), all installed together 4 trenches 4 Groups of Cables (2 cables per phase), 2 installed initially and 2 later. 4 trenches total 3 Groups of Cables (2 circuits shared between 3 Groups of Cables), all installed together 3 trenches 3 Groups of Cables (2 circuits shared between 3 Groups of Cables), 2 installed initially and 1 installed later 3 trenches total All-overhead Table 1. Description of Scenarios

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Trenches shown in black would be installed in Stage 1 of the work. Trenches shown on red would be installed in Stage 2 of the work. Figure 2 Comparison of scenario trench cross sections Circuit UGC km km

10

OHL km

55

No. of Groups of cable 4 3

65 20

45

4 3

0

65

(all overhead)

Staged

Scenario

No Yes No Yes No Yes No Yes No

1A.10 2A.10 3A.10 4A.10 1B.20 2B.20 3B.20 4B.20 65

Table 2. Table of Scenarios

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Note: Scenarios with three Groups of Cables (3A.10, 3B.20) have less substantial n-1 redundancy margins than Scenarios with four Groups of Cables (1A.10 1B.20) in meeting the contingency condition of 3,000 MW, as there is one spare Group of Cables available, compared with two spare Groups. Details of the cost estimates are given in Section 12, and in Appendices, Section 2 and Section 3. These are summarised below for convenience. The estimated costs in this feasibility study are expected to be representative to within a tolerance of ±30%.

1.5.2

Estimated capital cost: comparison between scenarios

The estimated capital costs of the scenarios considered are given in Table 45 in Section 12.2 and are shown diagrammatically in Figure 3. In Figure 3: - The total estimated capital cost for each scenario is the sum of the stage 1 and stage 2 costs. - The group of four columns on the left hand side represent the costs of the 10 km underground scenarios. - The group of four columns on the right hand side represent the costs of the 20 km underground scenarios. - In each pair of columns: o The left hand column represents the estimated capital cost if all the cables are installed at one time. o The right hand column represents the estimated capital cost if the cable is installed in two stages. - The blue sections of the columns represents the estimated capital cost of either: o The total of the un-staged scenarios or o Stage 1 only. - The red sections of the columns represent the estimated capital cost of the stage 2 costs of staged scenarios. - The column on the far right represents an all overhead line estimated capital cost for comparison.

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Figure 3. Estimated capital costs in 2009 dollars.

1.5.3

Estimated Net Present Value: comparison between scenarios

The estimated Net Present Values (NPV) of the life cycle costs for each scenario over a period of forty years are given in Section 12.4, Table 46, and are shown diagrammatically in Figure 4. The estimated NPV of life cycle costs includes all the capital costs, the cost of losses and the costs of spares and maintenance. The NPV takes into account when the costs are incurred and brings them forward to the present value of money. The methodology of calculating the life-cycle costs is described in Appendix, Section 3. NPV is a single number that expresses the estimated 40 year stream of costs in terms of an equivalent lump sum paid today. In Figure 4: - The four columns on the left hand side represent the estimated NPV of life cycle costs of the 10 km underground scenarios. - The four columns on the right hand side represent the estimated NPV of life cycle costs of the 20 km underground scenarios.

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- In each pair of columns: o The left hand column represents the estimated NPV of life cycle costs cost if all the cables are installed at one time. o The right hand column represents the estimated NPV if the cable is installed in two stages. - The red section is the total PV of the power losses in the transmission line over the 40 year life. - The blue section represents the estimated PV of all other costs.

Figure 4 Estimated NPV of the life cycle costs for each scenario

1.5.1

Summary of cost estimates

The comparison of the estimates of capital costs and NPV of life cycle costs in Figure 3 and Figure 4 show: - The all overhead line scenario with no underground cable has the lowest cost - The 65 km route scenarios with 10 km of underground cable have lower cost than those with 20 km underground. - The scenarios with three groups of cable are lower in cost than with 4 groups. This is true even though more costly switching equipment is required in the transition stations. (Note, if three groups of cables are used instead of four then the cable system will have less operating margin in contingency situations).

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- The staged scenarios have the lowest estimated capital cost, but only in stage 1. When the estimated cost of the stage 2 installation is added, the staged scenarios are higher in estimated cost than the un-staged scenarios. This is because of the need to re-mobilize the installation workers and equipment. - The staged scenarios have a lower estimated NPV of life cycle costs than the un-staged equivalent. The estimated NPV of life cycle costs for staged scenarios are 0.4% to 7.0% less than the estimated NPV of life cycle costs of the un-staged scenarios. The effect on cost of the number of Groups of Cable and of staging is shown in more detail in Section 12.5.

1.5.2

Cost differences between cable and overhead line

Details of comparisons between scenarios are given in Sections 12.5 and 12.6, Table 49, Table 50 and Table 51. The cost differences and ratios summarised in Table 3. Table 3 compares the estimated capital cost and the estimated NPV of the life-cycle costs as:   

Average costs of the 10 km and 20 km scenarios Average of the 10 km and 20 km scenarios’ cost differences compared with all-overhead line (Scenario 6) Average cost ratios compared to all overhead line, for the 10 km and 20 km scenarios Cable length Average of 10 km scenarios Average of 20 km scenarios 6

Estimated capital cost Estimated NPV of Life Cycle costs cost $M delta $M ratio cost $M delta $M ratio 730

348

1.9

757

345

1.8

959

577

2.5

977

565

2.4

382

0

1

412

0

1

Table 3. 500 kV Study Project costs, cost differences and cost ratios compared to all-overhead line

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Table 3 shows that for the 65 km 500 kV Study Project: 

The estimated NPV of the life cycle costs are greater than the estimated capital costs; however the average cost ratio for each scenario compared to the all-overhead line scenario is not significantly changed.



Increasing the length of underground cable from 10 km to 20 km, increases the average estimated NPV of life cycle costs ratio from 1.8 to 2.4 and the average difference in estimated NPV of life cycle costs compared to all-overhead line scenario from 345 $M to 565 $M.

Table 4 compares the average estimated capital cost per unit length of underground cable, both with and without the transition stations, to that of overhead line:

excluding all other equipment including transition stations and associated other equipment

Average cost ratio (installed underground cable to overhead line) 6.5 8.7

Table 4. Ratio of cost of underground cable and transition stations to an equal length of overhead line

1.6

500 kV Study Project duration

Details of the 500 kV Study Project duration are given in Section 13 and Appendix, Section 4 and are summarised below. The total times to procure, test and install the 500 kV Study Project were compiled by AltaLink and EPCOR a) from times supplied by the suppliers for cable manufacture and b) for the civil installation and construction durations. The work items are listed in Section 13.1 and 13.2 and the AltaLink & EPCOR schedule basis is given in Appendix, Section 4. The estimated duration and ISD (in service dates) are given in Table 55. The dates and durations for the staged options refer only to stage 1 of each scenario. Each of the dates given are for the supply and installation of all the equipment required for the particular scenario, including both cable and overhead line. The schedule was based on activities starting on February 01, 2010. As this date regresses, the ISD will also regress.

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Cable Length

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Number of Groups of Cables

km 4/2 10

0

Un-staged Time Scenario November 1, 2014 1A.10 57 months

November 1, 2014 57 months November 1, 2014 4/2 57 months November 1, 2014 3/2 57 months All Overhead Line March 29, 2013 3/2

20

In Service Date and Duration

3A.10 1B.20 3B.20 -

Staged Time December 1, 2013 46 months December 1, 2013 46 months November 1, 2014 57 months November 1, 2014 57 months -

Scenario 2A.10 4A.10 2B.20 4B.20 -

Table 5. Duration of cable supply and installation for each scenario The draft project schedules, summarised in Table 5, show that:  

1.7

The two 10 km long scenarios with two Groups of Cables to be installed in stage 1 have a cable supply and installation time of 46 months. All other scenarios have a cable supply and installation time of 57 months.

Power losses

Some power loss is expended as heat during the transmission of electrical power. The power losses as a percentage of the transmitted power for the 65 km 500 kV Study Project at the design average load of 2,000 MW are: - 0.44% for the scenario having 20 km of four groups of underground cable. - 0.35% for the all-overhead line scenario. The losses in an underground cable and overhead line are comprised of two parts: 

A ‘fixed’ part of constant magnitude that is independent of load current. The fixed losses are a function of the applied system voltage which is constant irrespective of the loading. The fixed loss of a cable system is higher than that of an overhead line. The fixed losses associated with a cable are:  Insulation losses in the XLPE insulation

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  

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Losses in the conductor due to the flow of charging current into the XLPE insulation Insulation and conductor losses in the reactors

A ‘variable’ part that is dependent upon load current, this being the heating of the conductor by the flow of load current. The variable loss of a cable system is lower than that of an overhead line, as the overhead line possesses higher conductor resistance than a cable. .

A ‘cross over’ load exists at which the losses in the cable are equal to the losses in the same length of overhead line.

1.7.1

Relationship of power loss to power transfer for the 500 kV Study Project

Teshmont performed a system study for AESO, Appendix Section 5, and compared the losses for each of the scenarios. Each scenario has different lengths of overhead line and cable connected in series and has reactors connected in parallel. In consequence the scenarios have a modified ratio of variable to fixed losses. A comparison of one circuit of a 65 km all-cable scenario with an all-overhead-line scenario in Figure 5 shows: 

The ‘cross-over load’ occurs at 1,700 MW at which the overhead line and underground cable scenarios have equal losses.



For transmitted loads up to 1,700 MW, the all-overhead line Scenario 6 has lower losses.



For transmitted loads greater than 1,700 MW, the underground cable scenario has lower losses. However, a single circuit will only experience loads in excess of 1,500 MW in contingency situations in which the other circuit is un-available. Thus the prospective power loss benefits of XLPE underground cables are unlikely to be realised in the 500 kV Study Project.

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Figure 5. Power losses for selected scenarios at different levels of transmitted power At loads less than the 1,700 MW ‘cross over’ load, the scenarios containing a portion of cable have a higher loss than Scenario 6, which is all-overhead line. The difference in losses compared to the overhead line Scenario 6 is lowest in those scenarios that contain a) the shortest length of cable and b) the fewest number of Groups of Cables. Figure 5 shows that: 

Scenario 2A.10 has slightly higher losses than the overhead line Scenario 6. This is because Scenario 2A.10 contains the smallest quantity of cable. It is the first stage of a staged option and comprises one group of cables (per circuit) instead of two. Note that the losses for Scenario 2A.10 are only plotted up to 1,500 MW as this is the limiting load for a single Group of Cables.

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

Scenario 1A.10 comprises two Groups of Cables and so has a load capability under contingency operation of 3,000 MW. The losses in Scenario 1A.10 above 1,700 MW are less than those of the overhead line Scenario 6 because variable losses in the overhead line conductor are greater than those in the underground cable conductor.



Scenario 5.B.65 comprises two Groups of Cables of 65 km length. The two Groups of Cable, under contingency operation, have a load capability of 3,000 MW:  At 3,000 MW the losses in the cable Scenario 5B.65 are 16 MW compared to 28 MW in the overhead line Scenario 6.  At a nominal low load of, say, 400 MW the losses in the cable Scenario 5B.65 are 6 MW, compared to 0.5 MW in the overhead line Scenario 6.

1.7.2

Cumulative power losses for the 500 kV Study Project

Teshmont calculated the losses for each scenario for 40 years based on the forecast average loads as follows: Up to and including 2026: 2027 and beyond:

457.3 MW 1,000.0 MW

For the average load of 457.3 MW in the period up to and including 2026, the average power losses for the relevant scenario Stages are presented in Table 6. Scenario condition for the loss calculation 2 Groups of Cables per circuit (Un-staged) 1 Group of Cables per circuit (Stage 1 only) 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) 1 Group of Cables per circuit (Stage 1 only)

Total loss

1A.10 2A.10 3A.10 4A.10

Length km 10 10 10 10

1B.20 2B.20 3B.20 4B.20

20 20 20 20

2 Groups of Cables per circuit (Un-staged) 1 Group of Cables per circuit (Stage 1 only) 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) 1 Group of Cables per circuit (Stage 1 only)

2.4 1.7 1.7 1.7

5A.65 5B.65

65 65

1 Group of Cables per circuit 2 Group of Cables per circuit

3.4 6.5

6

65

1 overhead line bundle per phase

1.0

Scenario

Table 6. Power losses for each scenario at an average load of 457.3 MW

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MW 1.7 1.4 1.4 1.4




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For the average load of 1,000 MW for the period 2027 and beyond, the average power losses for the relevant scenario Stages are presented in Table 7.

Scenario

Total loss

1A.10 2A.10 3A.10 4A.10

Length km 10 10 10 10

Scenario condition for the loss calculation 2 Groups of Cables per circuit (Un-staged) Stage 1 not applicable, Stage 2 identical to scenario 1 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) Stage 1 not applicable, Stage 2 identical to scenario 3

MW per circuit 3.9 3.7 -

1B.20 2B.20 3B.20 4B.20

20 20 20 20

2 Groups of Cables per circuit (Un-staged) Stage 1 not applicable, Stage 2 identical to scenario 1 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) Stage 1 not applicable, Stage 2 identical to scenario 3

4.4 4.0 -

5A.65 5B.65

65 65

Not applicable 2 Group of Cables per circuit

7.1

6

65


3.5

Table 7. Power losses per circuit for each scenario at an average load of 1,000 MW

1.7.3

Estimated NPV of cumulative power losses

The estimated Net Present Value (NPV) cost of the energy losses taken over the forty year analysis period is given in Appendix, Section 3 and is summarised in Table 8, which and shows that: 

The total NPV of the power losses for all scenarios ranges from 33 $M for all-overhead line Scenario 6 to 52 $M for Scenario 1.B.20.



The NPV of the power losses is 7.3% of the NPV Revenue Requirement* for Scenario 6, all-overhead line, and between 4.2 and 4.7% of the NPV Revenue Requirement for the scenarios that include cable. (*The NPV revenue requirement is the present value of capital and maintenance costs, etc, as detailed in Appendix, Section 3.)

The Net Present Value (NPV) of the differences in losses between those of the scenarios containing cable and the all-overhead line Scenario 6 are also given in Table 8, which shows that: 

The difference in NPV of the power losses for all scenarios ranges from 5 $M (Scenario 3A.10) to 19 $M (Scenario 1.B.20).



The difference in NPV of the losses as a percentage of the NPV Revenue Requirement ranges from 0.6% (Scenario 3A.10) to 1.6% (Scenario 1.B.20).

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Underground cable length

OHL length

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No of Groups of Cable

4 10

55 3

4 20

45 3

None

65

None

Staged

Scenario

PV Revenue Requirement $M

PV of losses

PV Loss difference from OHL

No Yes No Yes

1A.10 2A.10 3A.10 4A.10

756 727 696 691

$M 42 40 38 39

% 4.7% 4.5% 4.6% 4.7%

$M 9 7 5 6

% 1.0% 0.8% 0.6% 0.7%

No Yes No Yes

1B.20 2B.20 3B.20 4B.20

1,020 951 886 865

52 47 43 44

4.3% 4.0% 4.1% 4.2%

19 14 10 11

1.6% 1.2% 1.0% 1.0%

No

6

380

33

7.3%

0

0.0%

Table 8. PV of losses and of revenue requirement NPV is the net of PV of losses and PV of Revenue requirement.

1.8

Recommendations for next steps

The work described in this report has been the first step in evaluating 500 kV underground cables for use in the Edmonton region of Alberta. The next step would be to enact this report’s recommendations to quantify the risks associated with key items and further refine and optimise the cable system design. One key item is the minimum winter temperature that occurs in the Edmonton region of Alberta. 500 kV XLPE cable accessories have not been proven at these low temperatures. It is recommended as mandatory that proving tests be performed to demonstrate low temperature performance and identify whether any further development is necessary. The project risk can be reduced by installing the joints deeper in the ground to provide thermal protection. If a decision is taken to continue the study of undergrounding for any particular project, then the next steps are to perform:  Study of end to end reliability and availability  System and design studies  Additional engineering studies, as required Salient points relating to these steps are listed below:

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1.8.1

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Study of end to end reliability and availability

Study the reliability and availability of each scenario and select the optimum. The following should be taken into account:  The combined reliability and availability of all the equipment, e.g.:  Overhead lines  Underground cables  Switchgear  Reactors  The level of ‘n-1’ redundancy required.

1.8.2

System and design studies

Establish the actual current carrying requirements for the particular identified application. Perform a system design study under one or more of the following conditions:  Continuous loading  Emergency (short time) loading  Peak cyclic loading The cable system would be designed and optimised to fulfil the particular requirements. For example, if the peak load is only required for one or two hours in each period of twenty four hours, with a lower load for the rest of the time, then the resulting maximum conductor temperature would be less than that calculated for a continuous load. In this case a cyclic ampacity calculation is recommended to be performed in place of the continuous ampacity calculation with the objective of quantifying which of the following would benefit the application most:  Installation of the 2,500 mm2 cable size at a greater depth.  Reduction in the likelihood that three cables per phase would be required for the whole cable route to allow for a deep crossing under one or more major route obstructions.  Installation of the 2,500 mm2 cable in a narrower width of trench and swathe at the proposed depth of 1.3 metres.  Selection of a smaller conductor size than 2,500 mm2.

1.8.3

Carry out additional engineering studies, as required

Two of the key items for study are the low ambient temperatures and the small amount of service experience with 500 kV joints.

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1.8.3.1 Low temperature studies To investigate the feasibility of installing the joints at a depth greater than 1.3 metres to provide protection from low winter temperature. Calculate ampacity for:  The particular application loading conditions, as described in section 1.8.2.  The measured increase in ground temperatures with depth for the particular route. If the above study shows that the cables and joints can be buried at depths where they will not be exposed to extremely low temperature, then the project risk will be reduced. The manufacturers would then not have to demonstrate the performance of their joints at such low design temperatures. The following information should be obtained: From prospective suppliers:     

More detailed experience lists including those at lower system voltages and lower ambient temperatures. The minimum ambient temperatures that their cable systems have encountered. The types and numbers of accessories that they have supplied over a wider range of lower system voltages (i.e. 220-500 kV) for use at lower ambient temperatures. Any national or special tests that have been undertaken, which demonstrate low temperature performance. Any private developments that they have undertaken, which demonstrate low temperature performance (e.g. tests performed on 345 kV XLPE cable systems[3][4] in Montreal at the IREQ laboratory).

From utility companies, particularly those operating in regions of low ambient temperature:  

Details of their engineering practices and experience of low temperature operation. Details of National or in-house cable specifications concerning (a) limiting design temperatures and (b) tests to validate low temperature performance.

From electrical test houses   

If test houses have performed tests at low temperature on cable joints (e.g. tests performed on 345 kV XLPE cable systems in Montreal at the IREQ laboratory). Whether they have low temperature test facilities. Whether they would be interested in performing low temperature tests.

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If the time and uncertainties associated with proving the performance of the joint designs for low winter temperature operation are deemed to be unacceptable, then consider alternative actions:  

Evaluate the feasibility of externally heating the joints in winter. Select a tunnel installation with a controlled air temperature.

1.8.3.2 Obstruction studies To perform more detailed designs of how the cables could cross the obstructions on the route without compromising the power carrying ability of the circuit. In particular consideration should be given to:    

The depth of all identified obstructions. The way that the owner or operator of the obstruction would permit the cables to cross. Calculation of the ampacity if any heat is emitted from the obstruction (pipelines may contain fluid at temperatures above ambient) If directional drilling can be performed with sufficient positional accuracy.

1.8.3.3 Power system studies Perform more detailed study of how the transmission lines would operate within the wider electrical transmission network. Recommendations for further studies are given in Appendix, Section 5.

1.8.3.4 500 kV studies 

Seek from the manufacturers further supporting evidence, if available, on electrical service and test experience for joints at 500 kV.



If insufficient electrical service and test experience is available upon which to make a decision, then either:  Sponsor a long term prequalification test.  Await results of the first two years of service experience from the 500 kV Shanghai project, following its (proposed) commissioning date in 2010.  Install one or more short cable lengths, including at least one set of joints, on the Alberta 500 kV network.

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1.8.3.5 Maintenance studies 

Evaluate the feasibility and quantify the anticipated repair time following a cable fault in a direct buried installation at the winter ambient temperatures of the Edmonton region of Alberta.

1.8.3.6 Further discussions with prospective cable system suppliers 

Instigate discussions with cable manufacturers with regard to possible future development tests to demonstrate 500 kV operation and low temperature performance: 

Draft new test schedules to prove low temperature performance for consultation with the manufacturers.



Draft detailed schedules which would form the basis for enquiries to be sent to prospective suppliers at the project bidding stage, comprising a) special low temperature proving tests and b) pre-qualification (PQ) proving tests and type approval tests (TAT) based on the IEC 62067[1] specification.



Draft and agree detailed specifications for manufacturing and jointing quality control (QC) tests, noting that IEC (International Electrotechnical Commission) and AEIC (Association of Edison Incorporated Companies) specifications do not give complete coverage for all QC aspects.

1.8.3.7 Select how contracts should be divided between different suppliers For the large size and duration of the 500 kV Study Project construction work, and to reduce the risk of common mode failure, it is recommended that contracts be awarded to more than one supplier. If possible, each group of parallel cables should be supplied and installed end-to-end by a different manufacturer. One possible selection of supplier numbers for each scenario is given in Table 9:

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Scenario Number Route length

Detail Stage Number of trenches Number of suppliers 1A.10 10km 4 2 2A.10 10km 1 2 2 2 2 2 3A.10 10km 3 2 4A.10 10km 1 2 2 2 1 1 1B.20 20km 4 4 2B.20 20km 1 2 2 2 2 2 3B.20 20km 3 3 4B.20 20km 1 2 2 2 1 1 Table 9. Number of suppliers for each undergrounding scenario

The above is only typical; in the project schedule (Appendix, Section 4) a maximum of two suppliers was assumed. The eventual number of suppliers used would depend on their technical capability and ability to supply and install the volume of cables and accessories needed. One advantage of using multiple suppliers is the reduction in the likelihood of multiple outages because of common mode failure. The disadvantages are the difficulties of managing multiple subcontractors on the same project and the need to hold a wider range of spares.

1.8.3.8 Evaluate and identify resources necessary for the project Experience has shown that the most successful EHV (extra high voltage, i.e. 220 kV to 500 kV) cable projects have been those in which the utility took an active interest and so obtained a reciprocal response from the manufacturer. It is recommended that the Transmission Facility Owner’s (TFO’s) engineers be actively involved at the manufacturers’ works in:    

Auditing the factory prior to bidding and after awarding the work. Monitoring design progress. Witnessing the proving tests, prequalification tests, type approval tests and routine HV (high voltage) and material tests Observing the full-scale prototype jointing trials and jointer training.

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2

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REQUIREMENTS FOR UNDERGROUND POWER TRANSMISSION SYSTEM FOR THE 500 KV STUDY PROJECT

The following summarizes the functional requirements taken in this feasibility study for 500 kV AC underground cables for use in the Edmonton region of Alberta. These parameters were advised to us by the AESO. Where additional parameters were required, CCI provided information.

2.1

Functional requirement:

2.1.1

Functional requirement: power transmission

The functional requirement for power transmission is given in Appendix, Section 0. 

Voltage: 500 kV (nominal)



Total route length between end substations 65 km (nominal)



Two circuits



Power transmission requirement for ampacity calculations: Normal operation: Contingency operation:

1,500 MW (peak loading) at 500 kV per circuits loaded simultaneously 3,000 MW (peak loading) at 500 kV per circuit, with the second circuit out of service

For the purposes of calculating cable ampacity in this feasibility study, peak loading is defined as meaning constant, or substantially constant, loading for a period of time long enough for the cable to reach its design operating temperature. 

Average power transmission per circuit requirement for cost of loss calculations: Up to and including 2026: 2027 and thereafter:

457.3 MW 1,000.0 MW

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Notes:  

The peak load at any time during each year is expected to be some 1.5 times the average load during the year. e.g. if the average load is 1,000 MW, then the peak load is 1,500 MW. To allow for contingency operation (i.e. when one of the circuits is out of service) the remaining circuit is required to be capable of carrying the combined peak load of both circuits. i.e. For two circuits, each with a peak load of 1,500 MW, the maximum combined peak load is 3,000 MW. Each circuit must therefore be capable of carrying 3,000 MW.

This is shown diagrammatically in in Figure 6 and Figure 7. In normal operation as shown in Figure 6 each circuit on the overhead line shares the load by carrying 1,500 MW peak load and 1,000 MW average load in each circuit.

Figure 6. Overhead line: Normal operation In contingency operation as shown in Figure 7 one circuit on the overhead line takes the full load by carrying 3,000 MW peak load and 2,000 MW average load. The second circuit is depicted as being unavailable, for example out of service for maintenance or repair. Thus each overhead line circuit is required to be designed to carry a peak load of 3,000 MW.

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Figure 7. Overhead line: Contingency operation

2.1.1 

Functional requirement: ambient temperatures Maximum ground temperatures for ampacity calculations and cable sizing: - Summer:  Ground at: 1.3 metres depth: 20oC

- Winter:  Ground at: 1.3 metres depth: 0oC The above temperatures are based on those used in the design of the cable system for the recently installed Downtown Edmonton Supply and Substation 240 kV cable system. 

The minimum design temperatures for components are given in the following tables: Cable Splice (joint) Air insulated termination SF6 termination

Table 10 Table 11 Table 12 Table 13

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Cable Minimum ground temperature at 1.3 m depth for direct buried cable design (expected temperature is 0°C) Minimum air temperature for manhole cable design (expected temperature is -10°C) Minimum air temperature within deep tunnels for cable design (expected temperature is 0°C) Minimum air temperature within cut and cover tunnels for cable design (expected temperature is -10°C) Minimum outdoor air temperature for cable design (expected temperature is -30°C) Minimum indoor air temperature for cable design (expected temperature is 0°C)

Design temperature -15°C -20°C -10°C -20°C -50°C -10°C

Table 10. Minimum design temperatures for cable Splice (joint)

Minimum ground temperature at 1.3m depth for direct buried accessory design (expected temperature is 0°C) Minimum air temperature for manhole accessory design (expected temperature is -10°C) Minimum air temperature within deep tunnels for accessory design (expected temperature is 0°C) Minimum air temperature within cut and cover tunnels for accessory design (expected temperature is -10°C) Table 11. Minimum design temperatures for splices (joints)

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Design temperature -15°C

-20°C -10°C -20°C




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Air insulated termination Design temperature -50°C

Minimum outdoor ambient air temperature (expected temperature is -30°C) Minimum indoor ambient air temperature (expected temperature is 0°C) Maximum ambient air temperature

-10°C 36°C

Table 12. Maximum and minimum design temperatures for air insulated terminations SF6 termination Design temperature -50°C

Minimum outdoor ambient air temperature (expected temperature is -30°C) Minimum indoor ambient air temperature (expected temperature is 0°C) Maximum ambient air temperature

-10°C 36°C

Table 13. Maximum and minimum design temperatures for gas insulated terminations Notes on Table 10, Table 11, Table 12 and Table 13:

2.2



There is a margin of safety between the expected minimum temperatures and the design temperatures



These temperatures supersede those which were provided to potential suppliers of cable systems as listed in Section 9.2 and Appendix, Section 15. They were revised following a study of Edmonton temperature records, which are detailed in Appendix, Section 9.



For the purposes of this feasibility study, the minimum indoor ambient air temperature is assumed to be -10°C. Alternative temperatures could be considered if required as the indoor design temperature would be dependent upon the heating system within the building.

Scenarios considered

The following scenarios were studied for compilation of cost estimates, voltage studies and loss comparisons. These scenarios have different combinations of:

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- lengths of underground cable 10 km 20 km 65 km 0 km

(15% of the total route length (31% of the total route length) (100% of the total route length) (0% of the total route length)

(The scenarios which include 65 km of underground cable route are not considered in detail in this feasibility study. No cost estimates have been prepared for these scenarios as the installation conditions for such a route would vary somewhat from the installation conditions which have been studied. Further comments on the implications of a 65 km cable length are included in section 14.) - Number of cable circuits in the underground part of the route 2 cable circuits 3 cable circuits

With one or two cable per phase With one cable per phase

- Staging of installation  

Un-staged: installation of full 3,000 MVA capacity for each circuit or Staged: Stage 1:

Stage 2:

initial installation of part capacity on both circuits (1,500 MVA on either circuit, with the other circuit out of service) later installation of full capacity on both circuits (i.e. an additional 1,500 MVA per circuit)

A comparison of the cross section for each scenario of the Groups of Cables is shown in Figure 8 and a description of each of the scenarios considered is given in Table 14.

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Trenches shown in black are installed in Stage 1 of the work. Trenches shown on red are installed in Stage 2 of the work. Figure 8 Comparison of scenario trench cross sections

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Scenario

Staged

1A.10 1B.20 2A.10 2B.20 3A.10 3B.20 4A.10 4B.20 5A.65

No No Yes Yes No No Yes Yes N/A

5B.65

N/A

6

No

ER 381

19th February 2010 Description 4 Groups of Cables (2 cables per phase), all installed together 4 Groups of Cables (2 cables per phase), 2 installed initially and 2 later. 4 trenches (2 per phase). 3 Groups of Cables (2 circuits shared between 3 Groups of Cables), all installed together 3 Groups of Cables (2 circuits shared between 3 Groups of Cables), 3 installed initially and 1 installed later 2 Groups of Cables (2 circuits with 1 Group of Cables per circuit), for system studies only 4 Groups of Cables (2 circuits with 2 Groups of Cables per circuit), for system studies only All-overhead

UGC OHL Circuit km km km 10 55 65 20 45 65 10 55 65 20 45 65 10 55 65 20 45 65 10 55 65 20 45 65 65 0 65 65

0

65

0

65

65

Table 14. Scenarios considered The scenarios are shown schematically in: Scenario 1A.10 and 1B.20 Scenario 2A.10 and 2B.20 Scenario 3A.10 and 3B.20 Scenario 4A.10 and 4B.20 Scenario 5A.65 Scenario 5B.65 Scenario 6 Key to the symbols used in the diagrams:

Figure 9, Figure 10, Figure 11, Figure 12 Figure 13 Figure 14 Figure 15 Figure 16

The cable group cross sections X-X in Figure 9, Figure 10, Figure 11 and Figure 12 are shown in Figure 8.

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The switching arrangement is indicative only; more representative arrangements are given in drawing number 47DD-0001 in Appendix, Section 26. Scenario Number 1A.10 (10km route length). Un-staged 1B.20 (20km route length). Un-staged Figure 9 Scenario 1A.10 and 1B.20

The switching arrangement is indicative only; more representative arrangements are given in drawing number 47DD-0001 in Appendix, Section 26. Scenario Number 2A.10 2B.20

(Staged) (10km route length) (20km route length)

Stage 1 Stage 1

Figure 10 Scenario 2A.10 and 2B.20

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The switching arrangement is indicative only; more representative arrangements are given in drawing number 47DD-0004 in Appendix, Section 26. Scenario Number. 3A.10 (10km route length) Un-staged 3B.20 (20km route length) Un-staged Figure 11 Scenario 3A.10 and 3B.20

The switching arrangement is indicative only; more representative arrangements are given in drawing number 47DD-0004 in Appendix, Section 26. Scenario Number 4A.10 4B.20

(Staged) (10km route length) (20km route length)

Stage 1 Stage 1

Figure 12 Scenario 4A.10 and 4B.20

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Scenario Number

(For system studies only)

5A.65 (65km route length). Figure 13 Scenario 5A.65

Scenario Number

(For system studies only)

5B.65 (65km route length). Figure 14 Scenario 5B.65

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Scenario Number 6

No cable installed: overhead line only. Un-staged Figure 15 Scenario 6 : No cable

Figure 16 Key to scenario diagrams

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3

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BASIC DESCRIPTION OF 500 KV AC UNDERGROUND TECHNOLOGY

This Section is an introduction to the components that form the cable system, the purpose of which is to guide the reader in the terminology used in later sections.

3.1

Alternating current transmission system

Three conductors are necessary to form an alternating current (AC) transmission system. In North America the current alternates, (flows to and fro) at a rate of sixty times per second. Figure 17 shows different transmission circuits; an underground circuit of three cables, an overhead line circuit of three conductors and a gas insulated line circuit of three pipes. Each of the three cables and conductors must be in operation for the AC circuit to work.

Underground cable circuit

Overhead line circuit

Gas insulated line circuit Courtesy AREVA T&D

Figure 17. Three parallel lines or cables are required to form an AC circuit

3.2

Voltage, current and power

3.2.1

Voltage

The transmission system voltage for the Study Project is 500 ‘kV’, where kV is the symbol for 1,000 Volts, thus 500 kV is 500,000 Volts. The voltage is the force that, in electrical terms, drives the flow of load current from the generating station along the conductors to the consumer.

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Figure 18. Relative voltages of a 500 kV system The 500 kV system voltage is the voltage between each of the conductors of the single circuit overhead line, as shown in Figure 18. A feature of the AC system is that the voltage of each phase measured to ground is significantly less than 500 kV and is a value of 290 kV. The ratio of 500 kV to 290 kV is 1.73 (the square route of three).

Figure 19. Voltages between individual 500 kV cables Figure 19 shows that the voltages between each of the conductors of the underground cable are also 500 kV. However each of the conductors of the underground cable are surrounded by a metallic shield connected to ground, so the electrical insulation only has to withstand 290 kV, as shown in Figure 20. This has the benefit of reducing the thickness of the insulation that would otherwise be required.

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Figure 20. Voltage across the insulation of a 500 kV cable

3.2.2

Power

The unit of power is a Watt. A more useful unit used for power transmission is the Megawatt ( symbol: MW). One Megawatt is equal to 1,000,000 Watts. Power is calculated by multiplying the voltage (in Volts) by the current (in Amps).

3.2.3

Current

The current is the rate of flow of the electricity and is measured in Amps (symbol: A). When one circuit of a 500 kV overhead line is transmitting 3,000 MW of power, each of the three conductors is carrying 3,448 Amps. The power carried by a group of three 500 kV overhead line conductors is (3 x 290,000 V x 3,448 A) = 3,000,000,000 W, or 3,000 MW. It is normal for two or more groups of underground cables to be provided to carry a power of the level of 3,000 MW. In the case of two groups of 500 kV cables, each of the conductors carries 1,724 Amps. The power carried by one of the groups of 500 kV underground cable conductors is (3 x 290,000 V x 1,724 A) = 1,500,000,000 W, or 1,500 MW.

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3.3

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Component parts of the cable

Figure 21 shows the component parts of a 500 kV XLPE cable in more detail. The cable is a ‘single core’ design, having one insulated conductor inside it.

Figure 21. Component parts of a 500 kV XLPE cable The component parts of a single core XLPE (cross-linked polyethylene cable) cable and an SCFF (self contained fluid filled) cable perform similar functions, but utilise different materials. The SCFF cable is described in the following Section. The component parts of the XLPE cable are: 

The conductor. The conductor carries the load current. The larger the conductor, the higher the current that can be carried. The conductor in Figure 21 has a cross sectional area of high conductivity, annealed copper wires of 2,500 mm2. An alternative measure of conductor area used in North America is the unit ‘kcmils’ (thousands of circular thousandths of an inch). The 2,500 mm2 conductor size, Figure 21, is approximately 5,000 kcmils.



The triple extrusion. The triple layer is extruded onto the conductor in one manufacturing operation. The layers are: 

The conductor screen (or shield). This is a layer of carbon loaded conducting rubber. The purpose of it is to cover the irregularities in the outer surface of the conductor and to form an electrically smooth interface with the overlaying insulation. The material of the ‘semiconducting shield’ in a 500 kV cable is a ‘super smooth’ grade.

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

The insulation. This is a layer of XLPE (cross-linked polyethylene). The material used at 500 kV is an exceptionally pure, high quality grade and is called an EHV ‘super clean’ grade.



The insulation screen (or shield). In a 500 kV cable this is usually the same grade of super smooth, semiconducting material as the conductor screen. The purpose of it is to cover the insulation with a smooth conducting layer. The insulation shield may be considered to be electrically connected to ground for the purpose of this explanation. The shield entirely contains the 290 kV voltage within the XLPE insulation.



The purpose of the triple extrusion is to achieve a fully bonded smooth interface between the insulation and the shields. When the conductor carries load and becomes hot, the insulation and shields will expand and contract as one solid whole.



Cushioning layers. These permit the extruded cable and core to thermally expand without becoming damage by contact with the outer metallic layers. The layers must be electrically conducting to transmit the insulation charging current to the metallic ground conductor.



Metal sheath and ground conductor. This may be formed of one or two separate layers. In Figure 21 one thick walled aluminium sheath performs the dual roles of safely carrying longitudinal current of high magnitude in the case of a system short circuit and of providing a water-tight radial water barrier to water. Other cables may have a thinner metallic water barrier with a copper wire shield conductor (also called a neutral conductor in North America) to carry the short circuit current. The ground conductor also carries the insulation charging current in normal service operation back along the cable to a ground connection. In a long cable circuit this current may be of high magnitude.



Distributed Temperature Sensing Fibre. It is normal practice to include a DTS (distributed temperature sensing) system into the cable system. Pulses of laser light are shone along an optical fibre that is either included within the cable construction, as shown in Figure 110, or external to the cable in a separate tube as shown in Figure 75. As the pulse travels along the fibre, a small proportion of light is reflected backwards, from which the temperature of the cable at that position is calculated. Knowledge of the temperature is useful in planning the loading of the circuit and in identifying limiting hot spots along the route. It is more usual to include the fibre inside the cable in those cases in which the cable is to be pulled into a duct, due to the difficulties of installing a separate tube. A number of fibres (to allow for redundancy) are housed within a small diameter DTS tube that is normally stainless steel. The DTS tube is positioned underneath the metallic water barrier. In the case of a cable given an extruded metallic sheath, the DTS tube is helically wrapped between layers of

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cushioning tape. In the case of a cable with a copper wire shield conductor, the DTS tube is laid between two of the helically wrapped wires, as shown in Figure 110. 

3.4

Jacket. The jacket (also named an oversheath) is the outer extruded polymeric layer. The function is threefold a) to protect the inner metallic water barrier from corrosion, b) to electrically insulate the metallic barrier and ground conductors from ground and c) to be sufficiently robust to protect the cable during installation. High power carrying cable systems circuits such as that proposed for the 500 kV Study Project utilise ‘special sheath bonding’. The connections between the link boxes and the cable joints are made in such a way as to prevent the induced voltage from being able to drive a circulating current around the integral ground conductors. The downside of these special connections is that a voltage difference exists across the jacket to ground. If the jacket suffers undetected damage during installation or in-service the voltage difference will promote rapid corrosion and puncture of the metallic barrier. During routine maintenance work a test voltage is applied across the jacket to check that it has not become damaged. The manufacturer applies a conducting layer to the outside of the jacket to form a ground electrode and facilitate this test. The layer is either a conducting varnish or a bonded thin semiconducting elastomeric extrusion.

Cable system

The underground part of the transmission circuit for the 500 kV Study Project is named a ‘cable system’. The component parts of a short transmission system comprising two cable section lengths is shown in Figure 22.

Figure 22. The component parts of a cable system

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A 500 kV cable system or overhead line must always have a minimum of three single core cables in parallel. In this report the three single core cables are named a ‘Group of Cables”, and is shown in Figure 23. The three cables in each group are each connected to a separate ‘phase’ conductor of the AC transmission system. The phases are usually identified by letters as Phase A, Phase B and Phase C, or visually by colour, for example, as Red Phase, Black Phase and Blue Phase. The electrical connection to the AC transmission system is either made to other equipment within a substation, or to overhead lines within a ‘transition station’. Figure 24 shows a 400 kV transition station (also named a terminal compound) with the overhead line ending in a terminal gantry. Figure 25 shows the overhead line ending in a terminal tower. The terminal tower supports two separate 400 kV circuits, one to the left of the tower, Circuit 1, and one to the right, Circuit 2. Each overhead line circuit comprises just three ‘conductors’ each being one ‘phase’. (To improve efficiency each overhead line conductor comprises three ‘wires’ that are electrically connected together, being named a ‘bundled’ conductor. )

Figure 23. Two circuits comprising four groups of underground cables

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The bundled conductor is brought down to connect onto the end of the underground cable at the top of a ‘cable outdoor termination’. At the terminal tower in Figure 24 there are three cable terminations on each side of the terminal gantry, such that one overhead line bundle is connected to one underground cable termination. At the terminal tower in Figure 25 there are six cable terminations on each side of the tower, such that one overhead line bundle is connected to two underground cable terminations, this is shown diagrammatically in Figure 26.

Figure 24. 400 kV transition station with terminal gantry Courtesy Prysmian Cables & Systems

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Figure 25. 400 kV transition station with terminal tower Courtesy CCI

(For illustration purposes only) Figure 26. Two overhead line circuits connect to four groups of underground cable Figure 23 shows the cross section of the buried cables within the ground. The two groups of cables that form Circuit two (groups 3 and 4) are each installed in separate trenches. The trenches are spaced apart to allow the heat to escape more readily and to facilitate repair should one group of cables need to be excavated. All conductors become warm when they carry load current. The overhead line ‘bundled’ conductor can efficiently dissipate its heat directly to the air without getting too warm and this permits comparatively small size composite ‘wires’ of aluminium and steel to be selected.

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The underground cable cannot dissipate heat directly to the air so readily as it is surrounded both by a layer of insulation and by the depth of ground. Design measures are taken by the cable system designer to limit the temperature by a) to choosing a large conductor of high conductivity copper to reduce the amount of heat, b) spacing each cable wider apart and c) surrounding cable with a special backfill material to assist the flow of heat. If the current to be carried is too high for the cable size selected and it is not possible to manufacture a larger cable, then a second group of cables as shown in Figure 23 must be installed to share the current that each carries. The latter is the case for the un-staged scenarios of the 500 kV Study Project underground cables. Finally if sufficient heat cannot be dissipated by natural cooling, a forced cooled design would be considered as described in Section 3.11.

3.4.1

Component parts of the cable system

The component parts of the cable system are shown in Figure 22 and are described below:

3.4.2

Cable spans

The length of the cable span is the length of the cable that is delivered to site on a cable ‘reel’, also named a cable drum. For reasons of circuit reliability and economy, the cable supplier normally strives to deliver the maximum cable length that can be transported, this being limited by the height of road bridges, the maximum width of the road and the maximum permitted road weight or wheel loading. For a given route length, the installation of long spans reduces the number of joints needed to connect them together. The joints are the most sensitive part of the cable system and so increasing the cable delivery lengths increases the prospective reliability of the cable system. Two methods of transporting large cable reels by road are shown in Figure 27 and Figure 28 and by sea in Figure 29.

Figure 27. Delivery with cable reel axle crosswise Courtesy LS cables

Figure 28. Delivery with cable reel axle lengthwise Courtesy Nexans

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Figure 29. Loading cable reels in ship’s hold Courtesy Taihan Electric Wire Co.

3.4.3

Cable Terminations

The terminations are also named Potheads in North America and Sealing Ends elsewhere. The terminations are fitted to the end of the cable. The cable conductor has a connector (sometimes called a ‘stalk’) that protrudes into open air through the top of the insulator. The stalk permits electric current to flow into and out of the cable circuit. It is connected to other equipment in the substation or transition station. Figure 30 shows outdoor terminations fitted with long conical ‘insulators’. The stalk is at the high voltage of 290 kV and the insulator provides the long distance to insulate it from ground. Within the insulator is the means to control the electrical stress distribution such that there is a smooth transition from the very small thickness of the cable insulation to the very long length of the insulator. The top and bottom of the insulator are fitted with corona shields, whose function is to electrically shield the sharp edges of the top and bottom metalwork, and so prevent low level sparking in the adjacent air, named ‘corona’.

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Figure 30. Outdoor cable terminations Silec cable – General Cable Group Other types of terminations interface the cable with metalclad busbar equipment, for example into SF6 Gas Insulated Switchgear, these being named GIS terminations. As shown in Figure 31 GIS terminations have very much shorter length insulator, this is because of the high electrical strength of the pressurised gas.

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Figure 31, Cable terminations into gas immersed switchgear Courtesy Viscas

3.4.4

Cable Joints

Joints connect each cable span together. Joints in North America are frequently named ‘splices’. The three joints are always installed next to each other, either in single file, for example in a tunnel, or in line abreast, in the ground as shown in Figure 32 or in a vault as shown in Figure 33. It is covered overall with an electrically insulated joint protection box that serves the same function as the cable jacket. For high power circuits the joints would generally also include sheath sectionalising insulation (interrupted shield gaps) to eliminate the flow of current in the cable sheaths from one side of the joint to the other.

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Figure 32. A joint on a 400 kV XLPE cable prepared for burial

Figure 33. Part assembly of a joint on 240 kV XLPE cable inside a vault in Edmonton

3.4.5

Bonding equipment.

The equipment comprises ‘link boxes’ and ‘bonding leads’. It is required that the cable system be installed with a parallel ground conductor. In a long length 500 kV cable this ground conductor is built into the cable construction usually in the form of a metallic sheath or shield wires. At each end of the cable the ground conductor is connected solidly to a set of electrical ground electrodes. Bonding cables. The connections are named ‘bonds’ and the act of connecting is named ‘bonding’.

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Link boxes. To permit maintenance tests to be performed on the cable jacket it is necessary to have electrical access to it by disconnecting the bonding cables at each end. Disconnecting is performed by unlocking the link box and removing the connections (sometimes known as “links”) contained within, Figure 34. Different types of link boxes exist for above and below ground installation and for different methods of bonding. Diagrams for a cross-bonded cable system, the type that would be expected for a high power 500 kV circuit are shown later in this report (Figure 105 and Figure 106). Underground link boxes would be installed in an underground pit with only the (typically cast iron) manhole cover visible. Underground link boxes are commonly used in urban areas. In a specially bonded circuit, current flow is prevented by interrupting the cable integrated ground return conductors and shields at the accessories. The interrupted shield gaps experience unacceptably high transient voltages during circuit switching and lightning strikes and must be protected by connecting across them suitably rated nonlinear resistors called SVLs (sheath voltage limiters). The SVLs are voltage sensitive and “short” the insulated gap to limit the magnitude of the transient voltage. When the transient has passed, the SVL returns to high resistance and effectively becomes an “opencircuit.” Three cylindrically shaped SVL’s can be seen at the top of Figure 34.

Figure 34. An above-ground link box housing the components for a cross bonded position

Figure 35 shows link pillars (also known as kiosks and pedestals) in a field near to the positions of buried joints. The fences are the indicator that twelve buried 400 kV transmission cables cross the land.

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The fenced enclosures are to protect the link boxes from damage by cattle. Robust pillars and fences are fitted if mechanical harvesters are to be used.

Figure 35. Above ground link kiosks connected to 400 kV underground cable Courtesy CCI

3.5

Ancillary equipment

The ancillary equipment is the generic term for the following:     

Link boxes for bonding (XLPE and SCFF systems) Pilot cables for system telemetry Temperature-monitoring equipment Fluid reservoirs and pressure-monitoring equipment for SCFF systems Partial discharge* monitoring equipment for accessories in XLPE systems (optional)

*Note: A partial discharge (PD) is the occurrence of an electrical spark within a small air or gas-filled void (gap or split) in the insulation. The spark is formed by the liberation of the capacitive charge stored in the void when it breaks down. The name “partial discharge” distinguishes the event from the complete electrical failure of the cable, in which all of the energy in the insulation is discharged.

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3.6

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Hydraulic system for SCFF cable systems only

The hydraulic system ensures that SCFF cables are provided with dielectric fluid to achieve their designed dielectric strength during heating and cooling without experiencing extremes of pressure. Pressure ensures that contraction voids can never form in an SCFF cable. The designer calculates the size of external fluid reservoirs to absorb the volume of fluid thermal expansion when the cable is heated and to re-supply the fluid volume when the cable contracts. SCFF cables are described in Section 4.2.

3.7

Thermal design

The system thermal design ensures that the maximum possible current is carried by the cable system without exceeding the specified continuous operating temperature of the conductor and insulation. The designer selects the conductor size, the spacing between cables to limit mutual heating, and a stabilized backfill (as shown in Figure 74, Figure 75 and Figure 76) with low thermal resistivity. The stabilised backfill may be either compacted cement bound sand or a fluidised thermal backfill. The thermal properties of the material above the backfill and to either side of the trench must also be measured and approved. If the thermal resistivity of the native material is too high, then it will require to be replaced with an approved imported material. The thermal backfill and the trench filling materials must be compacted achieve to a specified value.

3.8

Thermomechanical design

The system thermomechanical design protects the cable and accessories from experiencing any excessive forces and movements that are generated when the cable is heated, cooled, and load cycled. Design solutions are selected to suit the method of cable installation. For example, in direct-buried or closely clamped (sometimes known as close-cleated) systems, the cable is rigidly constrained. In tunnels or on trays, the cable is unconstrained in wave or snake patterns. In a pipe or duct-manhole system, the cable is semi-constrained and is allowed to expand laterally. In duct-manhole installations, methods of constraint are required in joint vaults to protect the joints from movement. If the differential thermomechanical forces cannot be withstood by constraining the adjacent cable, either the cable system must be redesigned, or special accessories, such as anchor joints, must be installed to replace the conventional straight joints.

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3.9

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Installation design

Installation design covers all aspect of laying the cable and assembling the accessories to form the cable system.

3.9.1

Cable installation

Installation design specifies the methods and equipment necessary to install the cable into pre-laid ducts, Figure 36, or directly into the ground, Figure 37, to protect the cable from third-party damage by laying the ducts at depth and encasing them in concrete, and to cross obstructions such as roads, rivers, and other services, using solutions such as cable bridges, horizontal directional drilling (HDD), thrustbores, or tunnels.

Figure 36. Duct-manhole cable installation

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Figure 37. Direct buried cable installation The formation of the cables is important for ampacity and access for repair or replacement. Typical cable installation configurations are shown in Figure 38 and Figure 39. A A

B

C B

Flat spaced horizontal

C

Trefoil touching

A

B

A

B

C

C

Flat spaced vertical

Triangular

Figure 38. Typical formations for cables installed in ducts

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Figure 39. Typical formations for direct-buried cables For cable circuits such as the 500 kV Study Project, which are required to carry very large amount of power, cables are generally laid in a flat spaced, horizontal formation in groups of trenches similar to those shown in Figure 40.

Figure 40. Preparation of cable trench crossing agricultural land The main reason for the selection of cables in flat formation for high power capacity circuits is that the heat emitted from cable must be dissipated through the backfills and soils surrounding the cable to the ground surface; the more heat that can be dissipated then the more power that can be carried. The formation must therefore be designed to permit the maximum possible amount of heat to reach the ground surface without the maximum permissible temperature of the cables being exceeded. There is a mutual heating effect between cables which limits the amount of heat which can be dissipated from each cable. The further apart that the cables are positioned the less is the mutual heating effect. The cables are generally laid as far apart as possible to maximise the power that can be carried. The cables

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are also generally laid a flat, horizontal formation rather than a trefoil arrangement. With a trefoil arrangement, the lower two of the three cables would be further from the ground surface than uppermost cable. Because of this increased distance, less heat could be dissipated and less power could be carried. Cables in flat spaced formation are also easier to access should a repair be required. Consideration is sometimes given to the installation of a spare cable to permit the circuit to be quickly returned to service in the event of damage to one of the phase cables. This is unusual. Most cable laying configurations have symmetrical geometries, this being important if a specially bonded sheath system is employed to prevent circulating sheath currents. In such configurations an asymmetrically located fourth cable would unbalance the special bonding system and would require that the circuit be de-rated. The presence of a fourth specially bonded joint introduces complexity into the sheath bonding connections. The exception is a configuration which is initially designed such that a fourth cable can be located symmetrically, as shown as the right angled triangular formation in Figure 38 for duct-manhole systems. Such configurations are not appropriate for direct buried systems because they are difficult to install and difficult to repair without damaging the adjacent cables. For these reasons, if n-1 redundancy is required for a circuit, it is usual to provide an additional Group of Cables that shares the load in normal operation and which alone can carry full load in contingency operation.

3.9.2

Assembly of joints and terminations

A temporary building called a joint bay is constructed over the cable ends. The bay is made clean and dry. For high voltage cables the joint bay is well lit, heated and when necessary is air conditioned. Different manufacturers’ joints are shown during assembly, Figure 41, and after assembly, Figure 42.

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Figure 41. Jointing in progress in clean conditions

Figure 42. Completed joints

Courtesy LS Cable

Courtesy Sudkabel GmbH

The outer joint metal casing (‘joint shell’ or ‘joint can’) shown in Figure 41 form both a water-tight enclosure and an electrical continuation of the ground return conductor within the cable (formed by the metal sheath or shield wire conductor). In the ‘special sheath bonded’ system normally used for transmission class cables, both the cable sheath and joint shell experience an induced voltage. To prevent this voltage causing accelerated corrosion of the metal water barrier, the joint shell is encased within the ‘joint protection box’ shown in Figure 42. The joint protection box must retain its watertightness and its electrical insulation integrity throughout the life of the circuit. At intervals of typically one to two years the cables are taken out of service and a DC high voltage test is applied to confirm that the insulating and hence anti-corrosion protecting properties of the joint protection and cable jacket are sound. As part of the type approval process the joint protection is submitted to a combined water immersion, temperature cycling and voltage test, which is as equally searching as the high voltage type test applied to the primary cable and joint insulation. Outdoor cable terminations are assembled under similar clean conditions within the temporary structure shown in Figure 43.

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Figure 43. Temporary cable termination assembly structure

3.10 Route protection and identification It is important to warn people about the presence of the underground cables and to protect the cable system against third party interference. Should disturbance from dig-ins occur, it is important to be able to locate and repair any damage caused. Details of how this is achieves are given below. 

The cable system operator should put in place a policy with regard to any excavations which is communicated to all his own employees, to other utilities (including local authorities) and to all landowners along the route. This policy should give requirements as to how to notify the owner prior to commencing any excavations in the vicinity. It should also give requirements of any investigative work which must be conducted before excavations are permitted to take place. This can include the use of cable avoidance tools, ground radar, etc. The Damage Prevention Process in Alberta is recorded in Appendix, Section 10.



To enable cables to be accurately located after installation, it is vital that accurate route records are made whilst the cables are being installed. These must be maintained during the lifetime of the cable, and any diversions or repairs recorded.



The route should be clearly marked on the ground surface with robust markers that clearly identify the location, owner and type of the cable.

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

Routine surveillance should be conducted throughout the life of the cable system to check that the route markers are in place and that that there is no present or pending ground disturbance in the vicinity.



To give visual warning to any persons who might conduct excavations then a brightly coloured and labelled warning tape should be placed in the ground above the cables along the complete length of the route.



To give warning and protection to the cables and joints, rigid cover tiles should be placed immediately above the backfill surrounding the cables. The cover tile should be marked with wording to identify the owner and the presence of the electric cables. These should be rigid, robust and non-biodegradable.



To give warning and protection to the cables they are encased in a robust, hard backfill material such as cement bound sand or fluidised backfill. It is good practice to add a distinguishing colour to the backfill such as bright red.



The cable jacket which is usually extruded from HDPE/MDPE should be identified with embossed wording which as a minimum should include the words ‘Electric Cable’ and the voltage.



If the cable system is installed with a DTS system, this can also be configured to give an alarm and a location if a fibre is broken. The optical fibres may be position close to the surface of the cable or within the cable, the former prospectively providing earlier warning.



Routine electrical tests should be conducted to confirm the integrity of the insulation provided by the cable jacket, as any damage can result in corrosion and/or water entry into the cable.



Should the cable suffer an electrical short circuit due to dig in damage (or internal faults) then the cable must be disconnected automatically from the supply. Unlike overhead line, faults on underground cables do not clear themselves, so any ‘autoreclose’ system should be inhibited from operating on the cable.

3.11 Forced cooling If it is not possible to cool a cable passively by natural heat dissipation, it is possible to consider the use of a method of forced cooling. Four methods have been used and are described in [5]:

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

Lateral pipe cooling, in which the cables are laid in the ground at a sufficiently close spacing that a cooling pipe can be laid between adjacent cables. Water is pumped under pressure and circulated along one of the pipes and returned back along another parallel pipe. Depending upon the particular configuration, inlet temperature of the water and length of the cooling pipes, up to typically 80% of the heat that would otherwise flow to the ground surface is absorbed by a rise in the water temperature. Lateral pipe cooled systems have been used in special locations in which the width available to locate a cable trench is restricted. A typical example being under a road in a downtown location.



Integral sheath cooling, in which each single core cable is laid within a water filled pipe. Water is pumped under pressure and circulated along one of the pipes and returned back along another parallel pipe. 100% of the heat that would otherwise flow to the ground surface is absorbed by a rise in the water temperature. This system can be used for cables laid in the ground or in tunnels but has only been used for a very small number of special applications.



Trough and weir, in which the group of three cables is laid within a series of descending horizontal open water filled troughs, each separated by weirs to control the water flow.



A forced ventilated tunnel, in which the cables are supported by clamps (cable cleats) or laid on racks. Air is drawn from ground surface down a shaft and along the tunnel. A high proportion of the heat emitted by the cable is absorbed by a rise in the air temperature. A smaller proportion of the heat emitted by the cable is dissipated through the wall of the tunnel to the surrounding ground. The hot air is exhausted to atmosphere through a second shaft. This is the normal method for cooling cables installed in long tunnels. A forced ventilated tunnel system is less complex to design, operate and maintain than a water cooled direct buried system.

In closed water cooling systems, the heat from the hot water outlet pipe is extracted via a heat exchanger usually to air. If a high ambient air temperature is present in summer it may be necessary to also refrigerate the return water. If a sub-zero ambient air temperature is present in winter is necessary to protect the cooling pipes, pumps, and heat exchangers from damage by freezing. The disadvantages of a forced cooling system are: 

Availability of the circuit to carry load throughout its service life is dependent upon the operational condition of the cooling equipment, whereas a naturally cooled cable is not dependent upon such equipment and is always available to carry load.

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It is more difficult to extract heat from the joints than from the cable due to the increased thickness of electrical insulation. The means to increase heat extraction from the joints may increase the complexity of the joint design. For applications in which a naturally cooled system can be used, the cost of a forced cooled system is higher than a naturally cooled system.

3.12 Operation, maintenance and repair When the cable system is commissioned, the “as built” design, including the electrical parameters necessary to calculate the performance of the overall transmission system, is handed over from the contractor to the client, as part of the commissioning process. This would normally include operating and maintenance instructions, including recommendations for remedial action in the event of a failure. Repairs to EHV cable systems are discussed further in Section 7.22. To ensure that a) the heat can be dissipated from the cable system, b) the cable systems are not exposed to unacceptable forces or vibrations, c) the cable systems are not damaged by tree roots, and d) access for maintenance and repair of the cable system is not restricted, there will be restrictions of land use after cable installation.

3.13 Testing The test standards that include 500 kV are IEC 62067 (2001)[1], IEEE Std 404-2006[6] and IEEE Std 482009[7]. Standards for lower voltage cables are ICEA-S-108-720-2004[8], AEIC CS2-97[9], AEIC CS906[10], IEC 60840[11]. Testing of cable systems can be grouped into three major categories:   

Proving tests Quality tests, consisting of factory (or shipping) tests and commissioning (after laying) tests In service maintenance tests and measurements

In the event of a failure then diagnostic tests would be performed to investigate the cause and extent of a malfunction. Typical durations are given below for some of the tests, in planning of tests, allowance also has to made for manufacture of the components, erection of the test assembly, setting up of the measuring equipment, dismantling, and formal forensic inspection of samples.

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3.13.1 Proving tests The purpose of the proving tests is to demonstrate the adequacy of the design for the particular application. 3.13.1.1 Prequalification tests Long term formal Pre-qualification tests are performed to demonstrate satisfactory long term performance for a particular application. For XLPE cable systems above 150 kV to 500 kV, IEC 62067[1] requires the manufacturer to perform a Pre-qualification test as described below. 

Clause 3.2.4, IEC 62067. Definition: ‘Test made before supplying on a general commercial basis a type of cable system covered by this standard, in order to demonstrate satisfactory long term performance of the complete cable system. The Prequalification Test need only be carried out once unless there is a substantial change in the cable system with respect to material manufacturing process, design, and design levels. Note: A substantial change is defined as that which might adversely affect the performance of the cable system. The supplier should provide a detailed case, including test evidence, if modifications are introduced, which are claimed not to constitute a substantial change.’



Clause 13.1, IEC 62067: ‘When a Prequalification Test has been satisfactorily performed on a cable system, it qualifies the manufacturer as a supplier of cable systems with the same or lower voltage ratings as long as the calculate electrical stresses at the insulation screen are equal to or lower than for the cable system tested. Note: It is recommended to carry out a prequalification test using a cable of a large conductor cross-section in order to cover thermomechanical aspects.’

The test assembly must include each design of accessory and the test arrangement shall be representative of the installation design conditions. Figure 44 shows a 400 kV cable system being prepared for test. A one year test is performed, comprising 180 thermal load cycles and 8,760 hours on voltage. This is then followed by lightning impulse voltage tests and an examination of the components to demonstrate that no damage has occurred. The overall duration of the testing will this be in excess of one year.

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Figure 44: 400 kV cable system being prepared Figure 45: A Cable being prepared for type approval for long term testing

testing

Courtesy Nexans

Courtesy of Sudkabel GmbH

3.13.1.2 Extension to prequalification tests Clause 3.2.4, IEC 62067 states that, ‘The Prequalification Test need only be carried out once unless there is a substantial change in the cable system with respect to material manufacturing process, design, and design levels. Note: A substantial change is defined as that which might adversely affect the performance of the cable system. The supplier should provide a detailed case, including test evidence, if modifications are introduced, which are claimed not to constitute a substantial change.’ CIGRE Working Group B1.06 published Technical Brochure (TB) 303[51] to revise the qualification procedures. The technical brochure uses a Functional Analysis Method to evaluate the evidence and come to decision as to whether the prequalification test or other tests need to be repeated or not. TB 303 recommended than a new test be performed in cases where a substantial change had not been made as described below:

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Item 2.4, page 27, TB 303. ‘A simplified long term test (80) cycles called ‘Extension of Prequalification (EQ) test in case of’: 

‘Exchange of prequalified components’ (cable and/or accessories) with other components that are already prequalified in other cable systems with the same or higher calculated electrical stress at the insulation screen of the subjected system.’ o Authors: for example, this would allow a pre-qualified cable, or an accessory, to be supplied to another manufacturer to be used with his prequalified accessory, or cable, providing that the cable screen stresses experienced by the accessory were the same or lower.

 

‘Modification of a cable or an accessory within the same family in a prequalified system.’ This is defined in TB 303.

Purpose of EQ, Item 2.3.2, page 24, TB 303. ‘The 60 daily heat cycles without voltage plus the 20 heat cycles of the type test applied to the test loop are intended to allow relaxation of most of the mechanical stresses trapped in the cable insulation during manufacture.’ o Authors: this is the full IEC 62067 type test procedure, (Item12, page 31, therein) with amendments including:  

An additional 60 daily load cycles at the front end Two joints of each type, instead of one, to be in the configuration of the rigid or flexible installation fixing they were designed for.

3.13.1.3 Type Tests The satisfactory performance of a new design of cable and accessories is validated before supply by performing a formal Qualification Test (Type Tests). Figure 45 shows an XLPE cable being prepared for a type test. 

Clause 3.2.4, IEC 62067. Definition: ‘Test made before supplying on a general commercial basis a type of cable system covered by this standard, in order to demonstrate satisfactory performance characteristics to meet the intended application. Once successfully completed, these tests need not be repeated unless changes are made in the cable or accessory materials, or design or manufacturing process which might change the performance characteristics.’

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The tests include a range of material and electrical tests on cables and accessories, but do not require that they be installed in a way which is representative of how they are to be installed in service. The tests do not therefore simulate the thermomechanical forces that would be encountered in service. The Type Tests specified in IEC 62067 has a typical duration of six weeks, including 20 daily loading cycles.

3.13.1.4 Special Proving Tests (customer acceptance tests) In addition to requiring the pre-qualification test, most customers, when purchasing an EHV cable system for the first time for their application, specify that a full electrical and mechanical Type Test be performed for the exact cable system that they are to receive for their intended application, even if a prior type test had been performed for other customers. Some customers have their own in-house ‘Type Test’ specifications. These commonly have more stringent requirements particular to their application, than those of international specifications upon which they are based. In applications where a particular performance requirement is identified by the customer (utility) that is not included in national or international specifications, a special witnessed proving test is formulated and specified prior to the bid stage which the cable supplier is required to perform as a condition of supply.

3.13.1.5 Private Tests The cable supplier may separately identify particular performance requirements and may chose to perform in-house development tests, however, these are not necessarily disclosed or independently witnessed.

3.13.2 Quality tests The purpose of these tests is to demonstrate the quality and consistency of the manufacture and installation of the cable system for the particular contract. These are also contractual stages. Both these types of test are described for EHV cable systems in IEC 62067 and the AIEC CS9.

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3.13.2.1 Factory tests The quality of the cable and accessories is verified at the end of manufacture by performing routine tests (shipping tests, factory tests, production tests) at 100% frequency of product and by more onerous sample tests performed at a reduced frequency. 3.13.2.2 Site commissioning tests A formal acceptance test, which is also called a commissioning test, or after-laying test, is performed on-site on the completed cable system to verify that the installation workmanship is satisfactory, that no installation damage has occurred and that the circuit is safe to connect to the network. Figure 46 shows mobile, high voltage, AC test equipment that has been part unloaded from a truck and set up to test an XLPE insulated cable circuit.

Figure 46. High voltage AC commissioning test equipment Courtesy Nexans

3.13.2.3 In service maintenance tests and measurements Condition assessment tests are performed at periodic intervals during an installed cable system’s life to identify deterioration and permit preventative action to be taken.

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These are not covered by international specifications. A customer would specify the in-house requirements and specifications to which the supplier must comply. The customer would also require that the cable system supplier should provide operating and maintenance instructions as a contractual stage.

3.14 Permissible length of an AC underground cable circuit The technical limits to the length of an AC transmission system are a) the voltage drops arising from the flow of current through the conductor and b) the reduction in useful power carrying ability due to the capacitive charging current drawn by the insulation:  

A transmission class cable does not have a significant length limit due to voltage drop, because the conductor resistance is high and the inductance is low (a property arising from the geometry of the cable spacing and the magnetic field). A power cable does have a length limit due to a reduction in the useful power that can delivered because of the increase in charging current with circuit length.

The circuit length limit caused by capacitive charging current can be substantially eliminated by installing items of equipment called ‘reactors’ at intervals along a long route. The purpose of the reactors is twofold; to increase the power carrying efficiency of the cable and to limit voltage increases on the transmission system. A photograph of three reactors in a substation is shown in Figure 47.

Figure 47. Three reactors located in a substation

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Insulation charging current In an AC transmission system all types of electrical insulation draw current from the supply and ultimately from the power plants. This is termed insulation ‘charging’ current. This current is in addition to the current that is drawn through the transmission system by the load at the far end. The conductors in the overhead line or cable have a limited amount of current (the ‘rated’ current) that they are allowed to carry without overheating as the flow of current through their electrical resistance produces heat. The insulation charging current is subtracted from the rated current and what is left is the maximum load current that can be carried by the transmission system. An underground cable draws more current than an overhead line and so the load current is reduced more. The following factors increase the charging current:  

  

Thin insulation thickness; a cable has thin insulation and so will draw a higher charging current than an overhead line. The type of insulation; solid cable insulation draws a higher current than the air insulation around an overhead line, or the gas insulation around a gas insulated line. XLPE insulation draws about 130% more charging current than the same thickness of air. XLPE draws the least charging current of the types of available conventional cable. The length of the circuit; a 20 km length will draw twice as much charging current as 10 km. The system voltage; the same insulation thickness and length connected to a supply voltage of 500 kV compared to one of 24 kV will draw twice the charging current. The frequency of the AC supply voltage; insulation experiencing the North American frequency of 60 cycles per second, compared to the European 50 cycles per second frequency, will draw 20 % more charging current.

The distance between reactors is calculated for each individual application and may vary widely. In the 500 kV Study Project, reactors were located at the transition substations at each end of the underground cable for both the 10 km and 20 km long underground cable scenarios. In lower voltage cables of lengths less than approximately 20 km, the charging current is small in size and so only a small reduction of the cable’s rated current results (i.e. less than 4%) and is usually accepted. The charging current can be halved in magnitude by positioning an inductive reactor at the load end of the cable. The reactor may be positioned at a transition station or a substation. If a longer length of underground cable is required it may be necessary to consider installing reactors at regular distances along the route, however in practice this is unusual, one reactor is normally sufficient. In some circumstances the natural inductive reactance of the overhead line at the load end can be helpful in reducing the cable charging current. Conversely the presence of the cable capacitance can be helpful to offset the inductance of some overhead line circuits. In a long length submarine cable it is not physically possible to locate intermediate reactors on the seabed and so the size of the cable conductor is increased to carry the charging current without exceeding its design temperature. It is not usually

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economic or possible to do this with high power, land transmission cables as they tend to be already at the maximum size that can be manufactured. The property of the insulation material and geometry which defines its ability to draw charging current is called capacitance. The presence of the capacitance of the cable insulation at the end of an overhead line, (which has the property of inductance) can, under certain conditions, produce an undesirable increases in voltage. The location of a reactor at the end of the cable beneficially reduces this effect.

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STATE OF THE ART FOR 500 KV UNDERGROUND POWER TRANSMISSION Introduction

The state of the art is considered with respect to whether: 

An underground 500 kV AC cable system is feasible for the 500 kV Study Project in the context of achieving and maintaining a reliable transmission of power for a 40 year design life.



Technology exists to design and supply the type and number of components necessary to fabricate the cable system.

The required power level is 3,000 MVA, which is either a) shared between two parallel circuits in normal operation, or b) is carried by a single circuit in a contingency situation. The ampacity rating studies (Sections 7 and 9) have shown that: 

A conductor size of 2,500 mm2 is needed for an XLPE cable, but for an SCFF LPP cable, 3,000 mm² would be required. Proven service experience exists with 2,500 mm² conductors at both 400 kV and 500 kV AC system voltages with both XLPE and SCFF insulated cables. 3,000 mm² conductors have been used in DC LPP cables, which can utilise a different design of conductor to that required for AC cables.



Each AC circuit needs a minimum of two cables per phase, comprising a total of six parallel cables (3 phases and two cables per phase). The two circuits require 12 cables arranged in four groups, each group having three single phase cables.



Large numbers of cable lengths and joints are needed. The generic circuit lengths of 10 km and 20 km considered in the 500 kV Study Project (Scenarios 1 and 2) study require:  Total cable lengths of 120 km and 240 km respectively.  Total numbers of delivery reels, each holding up to 700 metres, of 180 reels and 360 reels for 10 km and 20 km respectively.  Total numbers of joints of 168 and 348 for 10 km and 20 km respectively. (The average reel length in the responses from prospective suppliers was less than 700 metres, requiring, say, 30% more reels and splices)

The design ambient temperature limits determined for the 500 kV Study Project are: Summer:

36oC 20oC

Maximum air temperature: Maximum ground temperature:

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Minimum air temperature: Minimum ground temperature: joint direct buried: joint duct-manhole: Minimum air inlet temperature, tunnel:

-50oC -15oC -20oC 0oC

The following review considers the technology of EHV cables (extra high voltage), which is defined as the transmission voltages within the range of 215 kV up to and including 500 kV. Numerically there are more 400 kV transmission systems in the world than 500 kV. Applications of 400 kV underground cable are therefore a good indicator of the availability of technology to be applied to the 500 kV Study Project

4.2

Self-Contained Fluid Filled Cables (SCFF)

SCFF cable is the type that preceded XLPE (cross-linked polyethylene) cable. SCFF cable is insulated with layers of lapped paper or laminated polypropylene paper (LPP) tapes and is completely impregnated with a low viscosity dielectric fluid (a synthetic, low viscosity hydrocarbon). SCFF cables were originally impregnated with a blend of mineral oil and were then called low pressure, oil-filled cables. The first 400 kV 2,000 mm2 large conductor, long length cable circuits containing joints were installed in the UK in the late 1960’s in direct buried applications. A 400 kV 2,600 mm2 long length tunnel circuit was installed in the early 1970’s[12].

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Figure 48. SCFF 525 kV 1,000 mm2 cable commissioned in Grand Coulee Dam in 1976 Notable applications of SCFF cable at 500 kV and above are:  Grand Coulee Dam, Washington, in tunnels. Two manufacturers supplied the paper insulated 525 kV cables, Figure 48, which were installed in tunnels. The conductor sizes are 1,000 mm2 and 1,250 mm2. The circuits were commissioned in 1976. Long term Proving Tests were performed[13] [14] [15]. 

Development tests on 750/1100kV paper insulated cables reported in 1979[16].



Vancouver Island. A subsea crossing of 39 km total length was commissioned in 1984[17], comprising two 1200 MW circuits of 525 kV, 1600 mm2 paper insulated submarine cables. A distributed temperature system was retrofitted to the cables and is described in a CIGRE 2006 technical paper[18].



Honshu-Shikoku Interconnecting Line[19] is a major land and bridge link across Tokyo Bay. The conductor size is 2,500 mm2 and it is insulated with LPP (laminated polypropylene paper). The link is a single circuit 22 km long, comprising a cumulative land length of 14 km and bridge length of 8 km. The number of accessories is 133 joints and six outdoor terminations. The circuits were

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installed in two stages in 1987 and 1993 and were commissioned in 1994. An LPP cable is shown in Figure 49. Canada, IREQ, long term tests on 800 kV LPP cable with accessories. The conductor size was 2,000 mm2. The tests were performed in 1991.

On technical grounds SCFF cable is a prospective second choice to XLPE for the Edmonton region of Alberta as it has proven 500 kV and low temperature operating capabilities. SCFF cable is more forgiving of short term high temperatures than XLPE even though it may suffer shortened life in the longer term. The low temperature capabilities are limited only by the temperature limit of the O-ring rubber seals in the accessories and by the temperature at which the standard hydrocarbon impregnant begins to thicken, this being around -40oC. The paper and LPP tapes are capable of operating at cryogenic temperatures (e.g. -270oC) in combination with a liquid helium or liquid nitrogen impregnant.

Figure 49. SCFF LPP 2,500 mm2 cable, similar to that commissioned in Japan in 1994 The substitution from SCFF cables to XLPE cables at 400 kV and 500 kV first began in the late 1980’s for short cable circuits with small conductor sizes (less than 1,000mm2) and without joints and in the mid 1990’s for long cable circuits with large conductors (1,200mm2 and greater) and with joints. The number of SCFF cable systems selected by utilities for new applications fell worldwide to minimal proportions during the period 2000-2005 due to their preference for XLPE cables. Since 2000 some SCFF manufacturing facilities have been closed. The surviving manufacturers with an SCFF capability have all switched to XLPE cable manufacture and at the present time have effectively mothballed their SCFF equipment. The expectation is that these manufacturers will dispose of their SCFF manufacturing and repair capabilities well within the 40 service life of the 500 kV Study Project.

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The maintenance of SCFF cable requires specialist equipment as skills. On grounds of maintainability SCFF cable is not recommended for the 500 kV Study Project.

4.3

Cross-Linked Polyethylene Cable (XLPE)

XLPE cable is the recommended first choice for the 500 kV Study Project. Although deceptively simple in construction, modern EHV XLPE cables have only been made possible by major developments in dielectrics science[20] [21], polymer chemistry, clean materials, manufacturing equipment and accessories[22] .

Figure 50. 500 kV XLPE cable XLPE has a combination of properties that have led to its development for high voltage, high power cable applications. The base compound is LDPE (low density polyethylene). Polyethylene is a thermoplastic which upon heating starts to soften at 60 oC to 70 oC and which at 107 oC changes from a white, semi-crystalline solid to a low viscosity transparent liquid. . When in liquid state a tube of it can be extruded over the cable conductor shield. The long chain LDPE molecule has side chains which permit it to be linked (cross-linked) to adjacent molecules; the material is then called XLPE. Cross-linking is a chemical process which is initiated by heating the liquid tube to approximately 200oC. This process is performed in a long metal tube called a (CV) continuous vulcanising tube. Instead of melting to become a liquid at 107 oC, it becomes a soft rubber (elastomer). The cross-linked insulation is then

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cooled to return to its original solid, white, semi-crystalline state. The cross-linking process permits the safe operating temperature of the cable insulation to be raised to 90oC, so that it can competitively carry similar levels of power to the SCFF cable. Additionally, some of the electrical properties of XLPE are superior to those of SCFF insulation, such as low power loss, which further improves its power carrying efficiency. The main thrust of the development of EHV XLPE cable has been to increase the design stress of such that thickness of insulation, overall cable diameter, cable span length, and most importantly, service life reliability are competitive with those of the highly evolved paper and LPP cables. The development of high stress XLPE cable systems is described by Attwood et al in 1998[23]. Figure 51 shows how the cable design stress at the conductor shield (screen) and insulation shield have been increased at higher system voltages. A key design parameter for the accessories is the stress at the cable insulation shield. Different manufacturers select different design stresses, the value in Figure 51 for a 500 kV cable, being approximately 7.5 kV/mm. This is similar to the average of the design stress values proposed by the manufacturers who participated in the 500 kV Study Project.

Figure 51. Increase of cable shield stresses at higher transmission voltages XLPE cable has now supplanted the SCFF type at all system voltages up to and including 500 kV. Numerically, there are now many service applications of XLPE cable at 400 kV, although individual times in service are comparatively short compared to SCFF cable. Notable early applications of XLPE 400 kV and 500 kV, large conductor, long length cable circuits with joints are:

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

1996 400 kV Metropolitan Power Project in Copenhagen[24], comprising a 12 km and a 9 km circuit length with a conductor size of 1,600 mm2. The circuits were installed direct buried. This is the first long length circuit of 400 kV cable with joints to be installed in Europe. A third 12 km circuit was installed in 1999. Two types of prefabricated joints were installed.



1998 and 2000 380 kV Berlin Diagonal Project[25] [26], comprising a 6.3 km and a 5.2 km double circuit length with a conductor size of 1,600 mm2. The circuits were installed in two tunnels in 2000.



2000 500 kV Shinkeiyo-Toyosu Project in Tokyo [27] [28] [29], comprising a 40 km long double circuit length with a conductor size of 2,500 mm2. The circuits were installed in a tunnel and commissioned in 2000. This is the first 500 kV XLPE circuit with joints and is still the longest EHV cable circuit in the world.



2004 400 kV Barajas Airport[30] in Madrid, comprising a 12.8 km double circuit length with a conductor size of 2,500 mm2. The circuits were installed in a tunnel.



2005 400 kV Elstree-St Johns Wood [31] [32] [33], London comprising a 20 km single circuit length with a conductor size of 2,500 mm2. The circuit was installed in a tunnel.

Progress in the adoption of 400 kV XLPE cable projects in Europe is recorded in Jicable technical papers in 2003[34] and 2007[35].

4.4

Advantages of extruded cross-linked polyethylene cables

4.4.1     

XLPE cable has the advantage over the SCFF type of : No risk of fluid leaks into the environment. Reduced likelihood of fire spread to adjacent circuits in tunnels and buildings. Reduced maintenance due to the absence of pressurizing equipment and the need to monitor and refurbish it. Inherent low energy loss due to the properties of XLPE. Reduced capacitive reactance due to the properties of XLPE.

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XLPE cable technology



The electrical strength of the cable is dependent upon minimising the number and size of a) particulate contaminants in the insulation and b) surface protrusions from the semiconducting shields23[36]. The design and manufacture of the high stressed insulation necessary for EHV cable applications requires careful QC (quality control) management of contaminant levels at the front end of manufacture i.e. the incoming insulation and shielding materials, the materials handling equipment and the extrusion equipment.



XLPE has a low resistance to partial discharging (low level electrical sparking in gas filled voids in, or on, the insulation). In manufacture the cable insulation must be kept completely free of voids and surface damage. Joints and terminations must be designed and assembled in such a way that air gaps are excluded and cannot reform during service life.



XLPE insulation is vulnerable to loss of electrical strength in-service due to the growth of ‘water trees’. The rate of growth is accelerated if a) water is present, b) the insulation and shields contain defects and c) if the electrical design Stress is greater than 2 kV/mm. The design stress in a 500 kV cable is approximately five times greater than this limit and so trees would rapidly grow. As yet no accepted means exists of continuously monitoring and detecting water entry into a cable through damaged outer coverings. It is accepted industry practice that EHV cable should have :  Insulation that is subject to a factory drying process to remove traces of the moisture that are chemically produced as a by-product of the cross-linking reaction.  A water tight metallic sheath and around accessories a completely water tight enclosure.  A longitudinally water blocked construction to prevent the flow of water along a complete span length should the outer coverings be punctured either by third party damage or by primary electrical failure. The spaces between the wires in the conductor are filled and the gaps under the metallic sheath are filled, typically by a water swellable tape.  A robust outer jacket to withstand abrasion during the cable installation process and puncture by stone/rock damage in-service. A robust, thick layer of extruded high density polyethylene jacket is normally applied for buried and duct applications.  A protected environment such as being laid in specially sieved or strained layers of backfill material (sometimes called bedding and blinding), or into a duct with clean, smooth walls and joints.  Regular maintenance checks on the integrity of the jacket during service life. The purpose is to detect and repair damage before the metallic sheath is punctured by corrosion. At intervals of typically no greater than one to two years a 5 kV DC voltage is applied between the metallic sheath and ground for 1 minute to detect

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and locate damage. For the purpose of testing, access to the sheath is provided by link boxes connected to the sheath at each accessory. The measures described above to protect and monitor the outer jacket and the metallic sheath of an XLPE cable are the same as those for the service proven methods used for SCFF cables. However, SCFF cables have the advantage that the internal fluid pressure is continuously monitored, such that an alarm is given when the sheath is punctured. No such warning is able to be provided for an XLPE cable. Manufacturers of XLPE cable have been freed from the constraint of applying a thick walled extruded metallic sheath to contain fluid pressure in SCFF cable types. They have developed lower cost designs with thinner metallic walls. These are prospectively more vulnerable to puncture by mechanical damage and corrosion. For direct buried and duct installations the XLPE cable can be expected to be exposed to moisture from the ground. It is important to specify a robust design of sheath and jacket and to ensure that routine maintenance tests on the jacket are diligently performed. In a lower risk, protected environment, such as a dry tunnel, advantage may be taken of a lighter design of metallic sheath.

4.5

Accessories for XLPE cable systems

The accessories (joints and terminations) are the critical components on which the reliability of the XLPE cable system for the 500 kV Study Project primarily depends. Accessories are of equal, if not of more importance, in achieving circuit reliability than the XLPE cable, and so the key international test specification, IEC 62067[1] and the key North American constructional specification, AEIC CS-9, both advocate the “systems approach” in which one manufacturer is responsible for the design of the system, the Proving Tests, the manufacture and the assembly of the cable and accessories. The critical location within the accessories is the electrically stressed interface between the outer surface of the cable insulation and the inner surface of the joint or termination insulation. It is essential that air filled gaps are eliminated from the interface. The above technological challenges resulted in the service experience of joints in Japan lagging that of cable by 10 years at each transmission voltage, as shown in Figure 52 and listed below:   

1988: 500 kV 800 mm2 XLPE. The first circuit with 500 kV XLPE (no joints). 1993: 275 kV 2,500 mm2 long-length cable circuit with joints commissioned. 2000: 500 kV 2,500 mm2 long length cable circuit with joints commissioned.

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Figure 52. Chart of XLPE cable design stress with system voltage.

In the first generation of 275 kV and 500 kV joint designs installed in Japan, the elimination of the critical interface was achieved by bonding the joint insulation to the cable insulation in an on-site extrusion moulding process (EMJ), which closely replicated the factory extrusion and cross-linking processes. The EMJ joint is shown diagrammatically in Figure 53 and a photograph of in-service joints is shown in Figure 54. 500 kV EMJ joints have given good service experience in the nine years since their commissioning in a 40 km long circuit in Tokyo in 2000. The extrusion moulded joint has the disadvantages that the assembly and inspection processes are complex and long. An assembly time of five weeks being required to complete a group of three joints. This time makes it unsuitable for present day cable projects and use as a maintenance spare.

Figure 53. Extrusion moulded joint (EMJ) schematic

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Figure 54. 500 kV XLPE cable and extrusion moulded joints in a tunnel Courtesy J-Power Systems Corporation

The second generation of joint designs use factory prefabricated components. The assembly time of three joints is typically ten to fifteen days The removal of air voids at the critical interface between the cable and joint insulation is achieved by:    

Application of high skill and diligence by the jointer in preparing and polishing the outer surface of the cable insulation on site to a high surface finish. Fitting onto the cable, a factory pre-moulded rubber insulating component with a smooth inner surface. Applying pressure to the rubber insulation to hold it in compressive contact with the cable interface. Designing the joint and selecting the materials such that the rubber insulation will remain in compressive contact during extremes of operating and ambient temperatures during the 40 year design life.

Three types of prefabricated joints (PJ) joints have been proposed by prospective manufacturers for the 500 kV Heartland Project, each being of the factory prefabricated type, in which the insulation is moulded or cast and is then subjected to an IEC 62067[1] high voltage routine acceptance test in the factory on each component. The proposed designs of joint for the 500 kV Study Project are: 

EPR OPJ (one piece joint). This OPJ has a pre-moulded insulation of EPR (ethylene propylene rubber). A schematic of the assembled joint is shown in Figure 55. When fitted to the cable the rubber OPJ has a residual stretch of approximately 25-30%, which applies

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compressive force to the cable interface. It is essential that the grade of rubber has a low compression set, so that the residual stretch and compressive force does not relax with time. The photograph in Figure 56 shows a 275 kV OPJ moulding with an injection moulding machine in the background. As part of manufacturing QC (quality control) it is usual to perform an X-Ray inspection, a stretch test and then to electrically test the OPJ.

Figure 55. One-piece joint (OPJ) schematic

Figure 56. 275 kV EPR OPJ in manufacture Courtesy of CCI 

Silicone rubber OPJ (one piece joint). This OPJ has pre-moulded insulation of silicone rubber. The photograph in Figure 57 shows a 400 kV silicone rubber moulding undergoing routine inspection and high voltage test in manufacture. The mechanism of operation is the same as that for the EPDM. In general silicone rubber components are soft and have good

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conformability to the cable surface, but some grades of silicone rubbers may have a lower tear strength than EPDM. Silicone rubber OPJ’s typically use a slightly lower design stretch and compressive force. In general silicone rubber would be expected to retain its elastic properties to lower temperatures than EPDM rubber.

Figure 57. 400 kV silicone OPJ in manufacture and routine test Courtesy Brugg Cables 

PJ (prefabricated composite joint). The PJ has a precast centre insulation of epoxy resin and two pre-moulded stress cones of either EPR rubber or silicone rubber (Figure 58). The stress cones are fitted onto the cable with a low stretch. Compressive force is applied by a solid thrust cone held in position by an annular ring of metallic coil springs. Each stress cone is thrust into a conical bore in each end of the epoxy resin centre casting. The length of the coil springs has to be sufficient to accommodate the thermal expansion and contraction of the stress cone, cable and epoxy resin casting whilst maintaining a near constant force. To accommodate low temperature operation a) the springs are of increased length and b) the metallic inserts cast into the epoxy resin centre casting (such as the high voltage electrode) and the grade of epoxy resin are carefully selected to give good crack resistance. It is usual for manufacturers to perform thermal shock tests and X-ray or ultra-sonic tests as part of the QC program, either at a reduced, or a 100%, sampling rate, in addition to the electrical withstand test. These are normal QC procedures in the cable industry for epoxy resin insulation.

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Figure 58. Prefabricated composite joint (PJ) schematic

Figure 59. Prefabricated composite joint (PJ) during assembly Courtesy LS Cable At the present stage in the technical evaluation for the 500 kV Study Project there is no preference for the type of prefabricated joint. It is necessary for each of the participating manufacturers to demonstrate a satisfactory low temperature capability on test. There is a lack of significant long term service experience in major 500 kV XLPE cable systems for the types of joints proposed for the Heartland Project. Some 500 kV test experience does exist. The available test experiences give confidence that some of the available types of joints will be capable of operating satisfactorily at 500 kV, either in their present form or with amended designs.

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Experience of 500 kV joints on 2,500 mm2 XLPE cables in service and on test is summarised below: 

The Shinkeiyo-Toyosu Project [27] [28] [29] in Tokyo is a 40 km long, double circuit, tunnel application has been in satisfactory service operation for nine years. The service proven designs of ‘field moulded’ joints are no longer offered by the original four manufacturers (now two manufacturers), nor are they preferred for future applications by the utility. The joint type is considered to be unsuitable for future applications in the role of either a primary joint or as a repair joint, because of a) the long times required for jointing and quality inspections and b) the complexity and size of the extrusion equipment and the clean jointing enclosure needed to house it. The field moulded joint has prospective attractions for operation in the low winter temperature of the Edmonton region of Alberta. The interface between the joint and cable cannot be disturbed as the extrusion process bonds the XLPE joint insulation to the XLPE cable insulation. Overall it is agreed that for manholes and vaults in direct buried and duct manhole systems it would be impractical to achieve high levels of cleanliness and to bear the long jointing times.



The Shibo Sub Station circuit in Shanghai is a 17 km long double circuit tunnel application, which is presently under construction, each with 630 metre section lengths and 78 joints. Each circuit is from a different supplier and has a different type of joint. One joint is of the OPJ type with EPDM insulation. The other is of the PJ type with EPDM insulation. The terminations are into GIS. The OPJ type of joint has gained much experience at 400 kV with large conductor cables. Some premoulded insulation uses EPR rubber[37][47] and some silicone rubber[38]. Both technologies can be extrapolated to 500 kV. Service experience for 500 kV OPJ types of joint has been gained on the Ochakovo circuits at Kaliningrad, Russia. This experience consists of one circuit of 2500 mm² cable with three joints commissioned in December 2008, and a further circuit of 2500 mm² cable with three joints commissioned mid 2009. There is also one 500 kV circuit of 800 mm² cable with six joints commissioned mid 2009. For all these circuits the terminations at one end are of the outdoor type and at the other end are of the GIS (gas immersed switchgear) type.



The 500 kV PJ type of joint was originally developed in Japan as the replacement to the field moulded joint. The PJ types have completed a number of 500 kV Prequalification Tests[39] which included a 6 month test in Japan at the Yamasaki test centre on a 3,500 mm2 cable in 2003 and a one year prequalification test in China at the Wuhan HV Research Institute on 2,500 mm2 cable in 2008. Figure 60 shows two 500 kV joints on test. The PJ joint was the first type to successfully complete 400 kV one year prequalification tests in Milan in 1996, these being funded by Berlin Electricity as a prequalification requirement for two tunnel circuits.

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Figure 60. 500 kV PJ joints on test Courtesy VISCAS corporation

4.6

Cumulative service experience of XLPE cable systems

The cumulative quantities of underground cables of all types in the voltage range of 220 kV to 500 kV is given in Table 15, which was abstracted from CIGRE Technical Brochure TB 338[40], Dec 2007, ‘Statistics of Underground Cables in Power Networks’. The table is ranked in descending order of the country having the highest quantity of cable circuit length. The worldwide cumulative quantities for each voltage range are given of a) underground cable of all types and b) for polymeric cable alone where this can be identified. Polymeric cable may be taken to be XLPE cable in the voltage range 315 kV to 500 kV and predominantly XLPE in the voltage range 220 kV to 314 kV. As most of the cable circuits analysed by CIGRE would be expected to consist of one Group of Cables, the terms “circuit” and “cct” are taken to be equivalent to a Group of Cables, i.e. three single core cables, one for each phase, throughout Section 4.6 of this report.

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Country Japan USA France Singapore United Kingdom Spain Italy Korea Mexico Canada China Germany Ireland Brazil Australia Austria Denmark Others TOTAL cct km Polymeric Non-polymeric Polymeric to total %

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19th February 2010 220 kV to 314 kV 315 kV to 500 kV 220 kV to 500 kV cct km cct km cct km % 1,440 123 1,563 22 663 536 1,199 17 903 2 905 13 651 111 762 11 496 166 662 9 479 80 559 8 197 34 231 3 0 221 221 3 170 3 173 2 153 16 169 2 156 0 156 2 45 65 110 2 106 0 106 1 22 55 77 1 15 58 73 1 5 54 59 1 0 52 52 1 75 15 90 1 5,576 1,591 7,167 100 2,230 3,346 40

430 1,161 27

2,660 4,507 37

Table 15 Cumulative quantities of underground cables of all types in each country An impression of the increasing accumulation of worldwide service with large conductor XLPE cable circuits containing joints is shown in Table 16. A summary of the cumulative lengths at each voltage is given in Table 17. Although there are 34 individual projects at 400 kV, which is many more than the 3 projects at 500 kV, the cumulative circuit length at 500 kV of 115.8 km is a comparatively high percentage (33%) of the 351.8 km length at 400 kV. In Table 16 the projects are ranked in ascending order of: System voltage in the range 220 kV to 500 kV. Date of completion of installation or commissioning. Projects still under installation, but which are expected to complete in 2010 are also listed.

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The information was obtained from the experience lists submitted by prospective manufacturers for the Heartland Project, from CIGRE Technical Brochure 338, December 2007[40] and the EPRI Underground Transmission Systems Reference Book, 2007[41]. Notes: Not all the manufacturers submitted complete experience lists for voltage of less than 400 kV and so the applications in the lower voltage range of 220 kV to 345 kV will be understated. Circuits may have been energized later than the years indicated and some may not be energized yet, so cumulative time in-service will be overstated. Equivalent three phase cable circuit length has been calculated in some cases as manufacturers prefer to supply cumulative lengths of single core cable and not circuit length. Where details of the project have not been declared, the likely presence of joints has been deduced from the presence of a high length of equivalent three phase circuit, so the number of projects containing joints will have been overstated, particularly for voltages in the 220 kV to 345 kV range. The type of installation was not always given in the manufacturer’s experience list, in which case the entry is left blank. The country of installation should not be taken to be the country of origin of the cable manufacturer. Projects in countries which are expected to experience a low winter ambient temperature relevant to the Edmonton region of Alberta have been included. In general manufacturers did not supply this data and so the number of low temperature installations will be understated.

System Voltage kV 220

Commercial Applications of Large Conductor XLPE Cable with Joints by Voltage, Conductor Size, and Circuit Length Year Conductor Size Circuit Length Country mm2 km of Installation 1995 1997

1,600 1,600

47.2 14.0

Qatar Ireland

1998 2002 2004 2005 2005 2006 2006 2007 2007 2007 2007 2009

1200 1600 1200 1,600 2,500 1,200 1,200 1,200 1,200 1,200 1,600 1,200

20.6 12.4 20.4 12.0 3.3 8.8 7.9 4.7 28.1 11.4 13.9 29.7

Sweden Vietnam Germany Italy Oman Russia Russia Russia Russia Russia Russia Russia

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Installation Type

Direct buried Direct buried and river crossing Tunnel Direct buried Direct buried and pipes Direct buried Direct buried




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1997 2001

1,200 1,200

22.6 4.6

France France

2001

1,200

17.9

France

2002

1,600

8.3

France

2002

1,600

7.4

France

1994 1998 2002 2006

1,200 2,000 1,267 1,267

7.7 33.0 8.2 38.0

India Singapore USA USA

1990 2002 2009

2,500 2,500 1,600

12.1 28.8 10.3

Japan Japan UK

Tunnel Tunnel Direct buried

2010

2,000

26.2

Russia

Direct buried

345

2000 2003 2006 2007 2008

2,500 2,000 1,600 1,600 1,500

20.6 19.6 13.9 3.8 13.0

Taiwan Korea USA USA USA

Tunnel Tunnel Duct manhole Duct manhole Duct manhole

380-400

1997 1998 1999 2000 2000 2001 2002 2003 2004

1,600 1,600 1,600 1,600 2,500 1,200 1600 2500 1,200

21.3 12.6 12.0 10.4 11.2 4.0 6.0 12.5 27.0

Denmark Germany Denmark Germany Saudi Arabia Iraq Spain Abu Dhabi Denmark

225

230

275

Duct bank Duct bank, trough and tunnel Duct bank, trough and tunnel Duct bank, trough and tunnel Duct bank, trough and tunnel

Direct buried Duct-manhole [42] Ducts and direct buried

330

Direct buried [24] [35] Tunnel [25] [26] [35] Direct buried [35] Tunnel [35] Direct buried Tunnel Direct buried direct buried and duct [35] [43] [44]

2006 2004 2005 2005 2005

2,000 2,500 2,500 2,500 1,200

16.8 25.6 20.6 5.4 10.4

Italy Spain UK UK Austria

2005

1,600

4.5

Netherlands

direct buried [35] [45] Tunnel [30] [35] Tunnel [31] [32] [33] [35] Tunnel Direct buried and tunnel [35] [46] Direct buried and duct [35]

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2005 2006 2006 2007 2007 2007 2007 2008 2009 2009 2009 2009 2010 2010 2010 2010 2010 2010 2010

1,200 2,000 1,200 2,500 2,000 2,000 1,600 1,200 2,000 2,500 2,500 1,600 2,500 2,500 1,200 1,600 2,500 2,500 2,500

1.3 2.7 8.2 13.3 3.5 13.2 1.5 7.8 1.3 6.0 16.4 5.0 22.0 11.2 12.8 4.4 7.3 11.0 1.8

Italy UAE Italy UK Italy Turkey Netherlands Netherlands Qatar Abu-Dhabi Qatar France Qatar Qatar Netherlands Netherlands UK UK UK

2000

2,500

80

Japan

Direct buried Direct buried Tunnel Direct buried Direct buried Direct buried and pipes Direct buried Direct buried [47] Direct buried Duct Direct buried Direct buried Direct buried and pipes Ducts [48] Direct buried Tunnel Trough Tunnel and bridge [27] [28] [29] [35]

2007 2010

2,500 2,500

1.5 34.3

Russia China

Tunnel

Table 16 Commercial applications of large conductor XLPE cable with joints by voltage, conductors size, and circuit length

System Voltage kV 220 225 230 275 330 345 400 500 TOTAL

Circuit km 234.4 60.8 86.9 51.2 26.5 70.9 351.0 115.8 997.2

Table 17 Summary of the cumulative lengths at each voltage of major XLPE circuits with large conductors, long lengths and joints The CIGRE Technical Brochure 379[49], published in April 2009, recorded the update of cumulative service experience of HV underground cable systems up to the end of the year 1995 in the voltage

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range of 315kV to 500 kV. The data included cable circuits of all conductor sizes with and without joints. The two dominant types of land cable system are the SCFF (self contained fluid filled) and the extruded XLPE system. Table 18 compares the quantities of cable and the numbers of each type of accessory for XLPE systems. Components

Type and Construction Sub-total Total Extruded or welded metallic barrier 229 cct km Cable Laminated foil metallic barrier 21 cct km 250 cct km All cable types Pre-moulded joint 336 Joints Site made joint 394 730 All joint types Outdoor, composite insulator Fluid filled 36 107 Dry type 12 Outdoor, porcelain insulator Fluid filled 59 Terminations GIS or transformer Fluid filled 193 205 Dry type 12 312 All termination types Table 18 XLPE Cable system component statistics: 315 kV to 500 kV Table 19 compares the quantities of cable and the each type of accessory for SCFF systems. Components Cable Straight joints

Terminations

Type and Construction Sub-total Total All cable types 724 cct km Straight joint 2,936 Stop joint 442 3,378 All joint types Outdoor, porcelain insulator fluid filled 775 GIS or transformer fluid filled 1023 1,798 All termination types

Table 19 SCFF Cable system component statistics: 315 kV to 500 kV Table 20 compares SCFF and XLPE cumulative quantities of cable and accessories at 315 kV to 500 kV. The table shows that the quantity of installed XLPE cable has not yet exceeded that of SCFF cable, although this will soon happen as the number of major XLPE projects has progressively increased since the first installation in 1997, whilst the number of new SCFF projects fell to near zero after 2002 to 2005.

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Components SCFF XLPE Total Cable 724 cct km 250 cct km 974 cct km Joints 3,378 730 4,108 Terminations 1,798 312 2,110 Table 20 Total cable system components installed up to end 2005: 315 kV to 500 kV Table 21 compares the statistics of XLPE cables from three sources. The statistics show a) a significant increase in the cumulative circuit length with time in the voltage range of 315 kV to 500 kV and b) that the Table 3 figures for the 220-314 kV range are understated. The latter is mainly attributable to the exclusion of circuits with small conductors and with no joints. System Voltage kV

220-314 315-500 TOTAL

Circuit Length (equivalent single circuit length) km CIGRE 379[49] CIGRE 338[40] Table 17, Compilation of Service Experience of Statistics of UG cables large conductor, long length Cables circuits with joints All circuits in-service All circuits in-service and Selected circuits in-service to in progress to and in progress to 2005 end 2006 end 2010 end 1,138 2,230 433 250 430 564 1,388 2,660 997 Table 21 Comparison of statistics of XLPE circuit from three sources

4.7

Electrical tests for XLPE cable systems

It is normal practice to require manufacturers to perform tests of proof on their systems before providing supplies to applications such as the 500 kV Study Project. The requirements for these tests are stated in international specifications for cables. Some cable system users formulate their own additional tests of proof to cover any special requirements for a particular application. It is recommended that the cable systems must pass the following proving tests before they are supplied to the 500 kV Study Project: - Prequalification test: a one year test to demonstrate performance when the particular cable voltage, cable conductor and joints have not been previously prequalified. A long term prequalification test layout is shown in Figure 44. - Type test: a six week long series of high voltage laboratory tests to prove the suitability of the cable system design selected for the study project. A type test assembly is shown in Figure 45.

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- Special proving tests: tests to demonstrate the reliability of the cable systems at Edmonton cold winter temperatures. The reliability of the cable system, and particularly that of the joints, needs to be proven for the extremes of temperature conditions it may encounter in service life. The Edmonton region has lower winter ambient temperatures than most other parts of the world where high voltage transmission cables of the XLPE type have been installed. Some manufacturers have performed limited low temperature testing, and have service experience in low ambient temperatures. None of the manufacturers offered experience at the low winter temperatures expected to be encountered in the region of Edmonton. To ensure that the 500 kV XLPE cable systems will be able to operate reliably at minimum ‘in situ’ temperatures, it is recommended that a specific series of tests be specified and performed.

4.7.1

Importance of prequalification tests for EHV XLPE cables

The application to install two 380 kV tunnel installations in Berlin in 1998 and in 2000 is of particular significance to the evolution of prequalification tests, because the utility BEWAG sponsored two series of tests[25][26] in Italy at the CESI Milan laboratories. These were based on the tests recommended in ELECTRA 151[50]. Six manufacturers took part in parallel tests in each series. Each manufacturer assembled a 100 m test loop with samples of each type of accessory and samples of each type of installation method (buried, tunnel, and duct). The first test series showed that the accessories, and in particular the joint, were a major weakness with only one manufacturer completing the tests, which was due to the robust design of a pre-fabricated composite straight joint. The first test series showed that factory-prefabricated joint insulation had a superior performance to hand-taped insulation in resisting disturbance from both heat and stress deformation and from conductor thermomechanical forces. Designs of prefabricated accessories were installed in the second test series, and these exhibited a greatly improved performance. Even then, only one manufacturer initially completed the second test series without distress or failure. The other five manufacturers either reassembled or replaced components and successfully completed the tests. The majority of utilities have since required evidence of the CIGRE 151, CIGRE 193 or their successor, IEC 62067[1], long-term prequalification tests to demonstrate compatibility of cable, accessories, and installation design. North American standards ICEA S-108-720-2004[8] and AEIC CS9-06[10] were issued in 2004 and 2006, respectively, and share the CIGRE and IEC approach of performing qualification and prequalification tests. A significant difference is that in Europe the manufacturer is free to optimize and to take responsibility for the design of the cable system, providing evidence of IEC tests are supplied,

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whereas in North America, the standards also specify the cable design stress limits and the dimensions of the cable, leaving the manufacturer with the responsibility for quality control. Manufacturers and utilities internationally have found difficulty in deciding when a change in cable design, accessories, installation, manufacturing plant, and materials warrants performing a new oneyear prequalification test. The tests are expensive and delay projects. CIGRE, therefore, published a revision of the qualification procedures in ELECTRA 303 (CIGRE 2006)[51]. The revision describes an ‘extension of qualification’ test procedure for changes in designs in EHV cable systems including their cables and accessories. The revision also recommends a prequalification test procedure for HV cable system design with high stresses when no earlier experience is available.

4.7.2

Prequalification test recommendations for the 500 kV Study Project

It is recommended that the IEC 62067[1] one year prequalification test be performed as an essential precaution for the 500 kV Study Project, even if manufacturers wished to claim exemption based on similar, but not identical, tests previously conducted. This is to reduce the risk arising from the combination of increased design stresses, the low ambient temperatures and the large supply quantities. The manufacturers have indicated for the operating stress within both the OPJ and the PJ joints proposed for the Heartland Project at the critical jointer prepared interface between the outer surface of the cable and the inner surface of the joint will be approximately 7 kV/mm, an increase of 17% over the typical value of 6 kV/mm at 400 kV. This is sufficient to justify the application of the Prequalification Test. The following is a list of some of the references that refer to prequalification test experience on 500 kV XLPE cable systems: Japan References[27][28][29] and Japanese cable manufacturers’ in house publications describe the 500 kV prequalification tests to Japanese Standards that were performed prior to the supply of the 500 kV 2500mm2 XLPE cable and extrusion moulded joints (EMJ’s) for the for the world’s longest 500 kV cable installation in Tokyo. One reference[39] describes a long term test to Japanese Standard JEC 3408 at the Yamasaki Test Centre of the Kansai Electric Power Company. The standard requires a six month test period. The test was performed on a 500 kV 3,500 mm2 XLPE cable and a prefabricated composite joint (PJ) with part EPR insulation. 3,500 mm2 is the largest known conductor size at a transmission voltage above 66 kV. To date this size has not been supplied commercially.

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Canada References[3][4] describes a 345 kV type test to Hydro Quebec Standard SN-49.1 performed at the IREQ laboratories in Quebec. The test was performed by a European manufacturer on a 345 kV 1,600 mm2 XLPE cable with a prefabricated joint of the EPR one piece type (OPJ) and both outdoor and SF6 gas immersed terminations. The cable was installed in a duct-manhole formation with the joints being located in an air filled chamber. This was followed by a series of long term tests comprising 138 days at 345 kV, 33 days at 400 kV and 364 days at 500 kV and a further 83 days at 400 kV. The 345 kV 1,600 mm2 cable and accessories therefore completed a prequalification test for 500 kV application. Europe This reference[52] describes a 400 kV prequalification test at the CESI laboratories in Milan by a European manufacturer to IEC 62067 on a 400 kV 1600 mm2 XLPE cable with two prefabricated joints of the EPR one-piece type (OPJ), two outdoor terminations and two SF6 gas immersed sealing ends. One joint and a length if cable was direct buried, another joint was installed in an air filled chamber, the two GIS terminations were installed in an air filled chamber. Lengths of cable were also installed in a duct section and in a tunnel section. The test installation completed 424 days at 400 kV including 184 heating cycles. Following the 400 kV prequalification test, the test installation went on to complete 408 days at 500 kV including 180 loading cycles. The 400 kV 1,600 mm2 cable and accessories completed a prequalification test for 500 kV application. China A long term 500 kV prequalification test to IEC 62076 was performed in 2009 by the Wuhan test station in China. The test was performed on a Japanese manufactured 500 kV 2,500 mm2 cable with a prefabricated composite joint (PJ) an outdoor sealing end and an SF6 gas immersed sealing end. The cable was direct buried and the joint was in a tunnel. The test report is in Chinese. If a manufacturer submits a prequalification test report, compliance with the following items needs to be validated:    

Is the test voltage 500 kV for the heating cycle voltage test? Is the number of heating cycles 180 and the total test period 8,760 hours as specified in IEC 62067? Is the conductor size 2,500 mm² or larger? Is the electrical stress at the conductor screen and at the insulation screen greater than or equal to that proposed for the 500 kV Study Project?

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  

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Are the accessory designs the same or equivalent to those being proposed for the 500 kV study project? Is the test arrangement representative of the installation design conditions as specified in IEC 62067? For the 500 kV Study Project, are cables and joints buried direct? Is the thermomechanical design appropriate for the 500 kV study project (particularly in terms of the mechanical restraint to the joints and terminations, and of the cable adjacent to the accessories)?

If the above items are not validated, can any exemptions be claimed for non-compliances using the recommendations in CIGRE Technical Brochure 303[51]?

4.8

Low temperature operation

Low temperature operation of the joints and terminations for the Edmonton region of Alberta is identified as posing a significant technical risk to achieving reliable service operation. The cable systems must be capable of operation at the minimum temperature that they may encounter in service. One of the worst case situations being when the cable is allowed to cool to the minimum ambient temperature prior to being re-energised. It is recommended that the risk be minimised to an acceptable level by selecting suitable joint and termination designs and by subjecting them to low temperature Proving Tests. It is recommended that suitable test specifications be formulated, as at present international specifications do not exist.

4.8.1

Ambient temperature levels for the Edmonton region of Alberta

In meteorological terms Alberta experiences a continental climate with a range of temperatures wider than the service experience that has been typically accumulated to date by EHV cable circuits. The range of ambient temperatures given for the Edmonton region of Alberta are: Maximum summer air temperature: Minimum winter air temperature: Air temperature range:

36oC -50oC 86oC

The maximum design air temperature is 36°C. Extreme temperatures of 34.5°C and 35.3°C have been recorded at Edmonton City Centre and Edmonton International weather stations (www.climate.weatheroffice.gc.ca) The expected minimum operating temperatures (in brackets) for the XLPE cable system in the 500 kV Study Project and the recommended minimum design temperatures, which include a performance margin, are:

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In air terminations: Direct buried joints: Duct-manhole joints: Tunnel joints:

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Design -50 oC -15 oC -20 oC -10 oC

The minimum winter air temperature of -50oC is considered to be exceptionally low, with respect to previous EHV XLPE cable and accessory experience. The corollary is that the range of conductor operating temperature of 140oC (-50oC off load in winter to +90oC on load in summer) is exceptionally high compared to that normally experienced. A significant proportion of terminations for EHV cable systems are installed outside and are exposed to the open air. They are expected to operate normally in the extremes of ambient air temperature and solar heating. Depending upon the type of installation, the cable and the joints have a measure of thermal isolation from the above ground air temperature and in consequence experience a reduced range of ambient temperature. Cables in the ground have the best protection from the ambient temperature. However burying the cable deeper is counterproductive as the heat generated by the cable conductor in summer must then flow through a higher thermal resistance path to reach the ground surface at its high summer ambient temperature. If cables are buried deeper then the cost of the cable system may be increased unnecessarily. The spacing between each individual cable must be increased or a larger size of copper conductor must be selected. If the widest spacing and largest conductor are already selected, as is the case for 500 kV Study Project in which a minimum of two cables per phase are required, then three cables per phase may have to be selected to carry 3,000 MVA. The minimum depth of burial in publically accessible land depends upon the regulations in the particular country. A typical minimum depth for HV and EHV circuits to the top of the cable is 900 mm, this being increased to 1,050 mm in farmland to avoid damage from agricultural equipment. The preliminary minimum depth of burial selected for the 500 kV Study Project was set at 1,300 mm to give a reasonable measure of protection both from ploughs and the low winter surface temperature. Ground isothermal plots indicated that the winter ground temperature at this depth would be approximately -3oC. The 1,300 mm depth is also supported by its use in the 240 kV XLPE DESS circuit to the north of downtown Edmonton. The DESS cable has an inbuilt optical fibre temperature monitoring system, the records for which were analysed to establish the coldest cable temperatures in the 2008/9 winter. It was found that the lowest temperatures were:    

At an outdoor termination position in-air: -46oC Cable at a spot position in a particular duct run: -8oC Joints within a vault: -7.5 oC Joints in the vault were colder than the adjacent cable by: 3 to 4oC

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More details of the temperature records are given in Appendix, Section 9. Experience with most EHV cable circuits is gained in countries which have a smaller range of temperatures, for example: a) in temperate climates with typical air temperature of 25oC maximum, 15oC minimum and 40oC range and b) in tropical climates with typical 50oC maximum and 0oC minimum, a range of 50oC. International specifications do not specify a minimum conductor temperature design limit for EHV cable systems. There would be an expectation for installation in a temperate climate that the conductor in an XLPE cable would operate from 90oC maximum, as given in international specifications, to -10oC, which is not. However, there is no published information to substantiate this lower temperature. Specified electrical prequalification and type approval tests require that the cable test installation comprising cable and joints be load cycled from a maximum conductor temperature of 95 to 105oC, depending upon the particular test specification, down to an unspecified minimum temperature given for a type test as 15oC above ambient with a maximum limit of 45oC. Type approval tests are normally performed inside a test house with a typical ambient air temperature of 15 to 20oC. Prequalification tests on the cable and joints are typically performed outside in a buried, duct-manhole or tunnel installation. They receive, by nature of their installation and degree of conductor and insulation heating, a measure of protection from cooling to sustained low winter air temperatures. Low temperature operation is recommended to be included in the design of the cable system. New low temperature proving test specifications are recommended to be drafted. The Proving Tests are recommended to be agreed with the prospective suppliers before the bidding process. The winter ambient air temperature and ground temperature are significantly lower than those for the 500 kV Tokyo and Shanghai applications and so this experience cannot be used in full to give confidence for use in the Edmonton Region of Alberta. Some low temperature service experience and test knowledge already exists amongst manufacturers. XLPE cables for lower system voltages and with smaller conductors have been supplied to countries with low ambient temperatures (e.g. Russia, Northern China, Iceland, Norway, Sweden, Finland, Northern Japan and Canada), although none have been advised to us to be as low as those in the Edmonton Region of Alberta. The key questions are whether a) the temperatures of any circuits have fallen to sub-zero ambient levels during a sustained outage and b) whether they were re-voltage energized under cold conditions. The manufacturers who replied to the request for 500 kV, low temperature operation responded positively. They advised outline designs of joint types and their estimated minimum operating temperatures, however these spanned a wide range (-30oC average, 0oC maximum and -50oC minimum). Generally only a limited basis of experience, whether service, engineering or test, was provided to substantiate these figures and so they should be noted with caution. Useful discussions concerning low temperature performance were held with the utility and the two Japanese manufacturers who had the experience of installing the nine year old 40 km long Shinkeiyo-Toyosu Project in Tokyo.

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It is recommended that:   

Discussions be held with other utilities and manufacturers to quantify their service experience in supplying and operating lower voltage XLPE cable and accessories in low temperature applications. Discussions be held with manufacturers and independent test houses to gain comments on an outline low temperature test specification. At a later stage of either technical prequalification or formal bid submissions, manufacturers provide a full technical justification for their proposed low temperature designs, based on calculations and preliminary, private in-house tests.

The method of funding the low temperature development work and Proving Tests requires consideration. The possibilities are:  

4.8.2

To require the selected manufacturers to perform the tests at their own expense after award of the contract and prior to commencing manufacture of cable and accessories. To wholly or partly fund the manufacturers to perform tests in advance of the bidding process as part of a prequalification requirement.

Low temperature risks

Prospective low temperature risks are listed below in decreasing order of ranking: Loss of radial contact of a rubber pre-moulded insulation component in a joint or termination with the cable XLPE insulation. Disturbance of the interface with the rubber component by longitudinal retraction of the cable insulation. Cracking of epoxy resin insulating components containing embedded metalwork. Splitting of premoulded rubber components. Failure of the conductor connectors in terminations and joints, due to increased thermomechanical retraction forces, noting that the large 2,500 mm2 conductor size will develop high retraction forces. Failure of the watertight seals between the metallic sheath and the accessory casings due to thermomechanical retraction, resulting in water entry and/or loss of electrical continuity of the screen conductors. Failure of the watertight ‘joint protection’ around the metallic casing, resulting in the electrical shorting of the sheath cross-bonding system, corrosion and water entry.

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Low temperature risks for joints In prefabricated joints, both the XLPE cable insulation and the rubber premoulded joint insulation have ‘glass transition’ temperatures at which they become rigid, brittle materials of high stiffness (modulus). It is essential that the premoulded rubber insulation retains sufficient elasticity, softness and compressive deflection, such that it is able to continuously maintain intimate contact with the XLPE cable insulation when both cables cool to low ambient temperature. If intimate contact is lost a void between the cable and the accessory will form in which incipient electrical distress in the form of partial discharging will occur leading to complete electrical failure of the accessory. The commencement of the change from an elastomeric to a brittle state is not easily predictable from bench top tests on small material samples, as it depends upon the particular loading conditions. Having evaluated the material it is recommended that Proving Tests be performed on the complete accessory assembled on the cable whilst voltage energized under a range of operating conditions e.g.:   

Sustained minimum ambient temperature Cyclic temperatures Transient temperatures,

Each of the above loading conditions should be performed both with and without axial thermomechanical loads applied by the adjacent cables to the joint. The joint protection that surrounds the metallic casing is at risk of disturbance, cracking or loss of adhesion. The international test specification IEC 62067[1] gives tests on outer protection for buried joints. The test comprises the application of 20 temperature cycling whilst immersed under one metre head of water, followed by electrical tests on the cable jacket, joint protections, sheath interrupter insulation and bonding lead. The maximum temperature is within 15 to 20oC of the design temperature of 90oC (i.e. 70 to 75oC) and the minimum temperature is within 10oC above the ambient of the test house (unspecified). It is recommended that the method of test be amended to cool the joint down to 20oC during temperature cycling.

Low temperature risks for terminations The low temperature operation risks are greater in an outdoor termination, because of the -50oC ambient temperature. The cables can either be terminated directly into an air insulated termination or into metalclad gas insulated switchgear terminations (GIS). (The abbreviation GIS should be taken to refer to metalclad gas filled terminations as these may or may not be connected to switchgear). Three designs exist for 500 kV XLPE outdoor terminations: 

‘Capacitor cone and insulator’, Figure 61. A stress cone formed of either moulded rubber or wrapped polymeric sheet is fitted to the lower part of the cable core

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immediately adjacent to the cable core shield termination. A long cylindrical capacitor cone is fitted above the stress cone. Cylindrical electrodes comprising layers of aluminium foil are interspersed between cylindrical layers of a special type of insulating paper. The top foil is connected to the conductor and the bottom foil to ground. The length and overlap of each foil gives a uniform voltage distribution from the top to the bottom of the termination that is better than the other types described below. A cylindrical insulator of glazed porcelain or of moulded silicone rubber sheds on a fibre reinforced epoxy resin impregnated tube (a ‘composite’ insulator). The insulator is fully filled with an insulating fluid. To prevent swelling of the polymeric cable and accessory insulation a low viscosity hydrocarbon oil is not selected. Either silicone fluid or a PIB fluid is used. This design has the longest service experience at 500 kV. Low temperature risks are that a) the insulating fluid would become too viscous to maintain impregnation of the capacitor cone and b) that thermal contraction may disturb the insulating components and fluid seals.

Figure 61, Outdoor termination with capacitor stress control

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

‘Stress cone and insulator’. A premoulded rubber stress cone insulator is stretched and slid over the cable insulation. A porcelain or composite insulator is fitted and filled with insulating fluid. Low temperature risks are the same as those described for ‘capacitor cone and insulator’ termination and the prefabricated joints.



‘Prefabricated stress cone and insulator’, Figure 62. This is a variant of the ‘prefabricated and insulator’ type. Firstly, a premoulded rubber stress cone insulator, as described above is fitted. An epoxy resin casting with a conical bore is then fitted above the stress cone. The rubber stress cone is inserted and held into the conical bore by a bank of helical metallic springs. The purpose is a) to increase the contact pressure at the critical moulding/cable interface and b) to replace the fluid in the high electrically stressed zone around the stress cone with high strength epoxy resin. Low temperature risks are the same as those described for ‘capacitor cone and insulator’ termination and the prefabricated joints.

Figure 62. Outdoor termination with prefabricated composite, premoulded stress cone The following three designs exist for 500 kV GIS terminations. The low temperature risks are the same as those described for the outdoor terminations, with the additional risk that cracks may occur within the epoxy resin insulator adjacent to the cast-in metalwork.

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‘Capacitor cone and insulator’. This is closely similar to that described for the outdoor design. The insulator is a cylindrical tube of cast epoxy resin of significantly shorter length. ‘Stress cone and insulator, wet design’. This is closely similar to that described for the outdoor design. The insulator is a cylindrical tube of cast epoxy resin of significantly shorter length. It is named a ‘wet’ design because the insulator is filled with dielectric fluid. ‘Prefabricated stress cone and insulator, dry design’. The design is closely similar to one half of a prefabricated composite joint. The external insulator is an epoxy resin casting with a conical bore. The rubber stress cone is inserted into the conical bore and held in intimate contact with the interfaces by a bank of helical metallic springs. The design does not require to be filled with dielectric fluid and so is named a dry design. The advantage is that no monitoring or maintenance checks is required to check that the dielectric fluid is at the correct pressure and has not leaked either into the cable or into the environment.

Low temperature risks for the XLPE cable The cable remote from the accessories is considered to have a good low temperature performance providing it is not subjected to movement when cold. The extruded XLPE insulation and MDPE or HDPE jackets are robust mechanical entities. Test specifications exists to test the cable insulation and the jacket for conditions likely to be experienced during installation in temperate climates, these being bend tests, abrasion tests and impact penetration tests. It is recommended for the 500 kV Study Project that these tests be performed at low temperature, for example at -20oC, to determine the minimum safe temperature at which the cable can be installed a) to determine the duration of the season available for installation and b) the ambient temperatures at which replacement cable could safely be installed following a service failure in winter. In the UK it is practice for the cable reel to be preheated to above -5oC for an MDPE or HDPE jacketed cable and to only install if the ambient temperature is above -5oC. It is believed that other countries have lower limits. Standard practice for medium voltage XLPE cables is to store indoors overnight in a heated garage before installation in cold weather. Experience near Edmonton was that a medium voltage cable that was at -35°C temperature split the insulation to the conductor when an attempt was made to install it. The limiting minimum ambient temperature for installation of a 500 kV, 2,500mm², cable must be quantified for the Edmonton region of Alberta. Whilst the HPT is not planning to install any cable during the winter months due to the risk of damage to a cable reel, a repair strategy would have to be prepared for all seasons. In the cable factory, thermal contraction to ambient temperature occurs after a) the XLPE insulation extrusion and cross-linking processes and b) the MDPE or HDPE jacket extrusion process. The thermal contraction produces significant locked-in stress and strain. A manifestation of this is that local longitudinal contraction occurs when the cable is cut during jointing. Most of the longitudinal contraction is prevented by the distributed radial compressive and friction forces. The risk in temperate

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climates exists that excessive contraction will occur at the accessories. Specifications exist to test cable samples in the factory to ensure that the magnitude of the contraction does not exceed a prescribed limit. For the 500 kV Study Project it is recommended that Proving Tests be formulated to ensure that damage due to excessive contraction does not occur to the cable or terminations when the cable is cooled to -50oC.

4.9

Types of cable installation

There are three types of installation that can be considered for a 500 kV cable land installation:   

4.9.1

Direct burial Duct-manhole Tunnel

Direct Buried Installation

A direct buried installation in open land as shown in Figure 63 is the most efficient in terms of installation costs as trenches of long length can be cut to match the maximum cable reel length. It also slightly more efficient than a duct system in dissipating heat by natural cooling to the ground surface, so it may be possible to select either a closer cable spacing or a smaller conductor size. In response to inquiries for the Heartland Project, prospective manufacturers proposed maximum reel lengths of up to 700 metres for the 500 kV 2,500 mm2 cable.

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Figure 63. Typical direct buried 400kV cable trench containing one Group of Cables A direct buried system gives the most intimate mechanical support to the cable and joints from the thermomechanical loads generated by the expending and contracting cable conductor as it heats and cools. A direct buried system is named as being thermomechanically ‘rigidly constrained’. The cables, joints and terminations are prevented from moving either longitudinally or laterally, but in consequence develop maximum axial loads during heating and cooling. The conductor connections, the termination structures and the joint supports must be designed to withstand these forces. It is good practice to a) encase the cables within the firm support and protection provided by cementcontaining materials such as cement bound sand (CBS) or fluidised thermal backfill (FTB) that set solid and b) to sit the joints on a concrete pad, hold them by clamps (sometimes known as cable cleats) and support them on CBS or FTB. CBS and FTB are designed to be sufficiently strong to support the cables and withstand their loads, whilst being sufficiently weak to be removable in the event that the cables have to be uncovered to effect a repair. In practice some materials can be difficult to remove without damaging the cables so it is important to approve the material and to check it immediately prior to use. In locations vulnerable to traffic ground loading (temporary or permanent traffic movements), the cables and the joint bay may also be covered with a metallic plate. In open land it is advantageous to dig a trench with battered sides, i.e. sides that are sloped to avoid collapse, thus avoiding the cost of shoring (sometimes referred to as close-timbering) a rectangular shaped trench. Close timbered trenches are required in locations of restricted width such as a)

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installation in urban streets and b) increased depth in open land, such as crossings under route obstructions (roads, railroads and pipelines). Direct burial is not common in North America for EHV cables. The disadvantages of a direct buried installation are:        

To install a given length, say 700 metres, of direct buried cable then the same length of trench must be open. In built up urban areas open to traffic and the public it may be difficult to obtain permission to open a long trench. Setting up the trench for cable installation is complex and labour intensive. Skill and experience are required. Fencing and high security is required on the open trench and on the cable within it, both to protect the public and vehicles from falling in and to protect the cable from malicious damage and theft. In certain environmentally important locations it may be required to fence the trench and construct temporary bridges to permit indigenous creatures to cross the trench. To keep to the project schedule it is essential that the three reels holding the particular lengths of cable for the designated open trench are delivered and are set up on time. Unpredictability of cable laying due to delays and trench damage by heavy rain, flooding and snow falls. The external protection is generally less than that provided by ducts encased in a concrete duct bank. Direct buried cables are thus more susceptible to “dig-ins” and third part damage. Fault location and repair requires excavation of the Right of Way, work in proximity to other cables and the addition of repair splices in the circuit.

4.9.1.1 Installation of the direct buried system The trench is first dug; then a specially sieved or strained layer of thermally stabilised bedding, typically dry CBS or fluid FTB is laid, compacted and smoothed. Cable rollers are then placed at close spacing along the trench and skid plates are positioned around bends in the trench. Having ensured that the bottom of the trench is clean, one cable is pulled in. 500 kV XLPE cables with a robust metallic sheath and jacket are likely to be pulled in by a ‘nose-pull’. The leading end of the cable is attached to a steel wire bond that is wound onto a powered winch positioned at the remote end of the trench. The risk of damage to the metallic sheath on a 500 kV SCFF cable must be avoided as it contains the pressure of the dielectric fluid. If it considered that there is risk of damage to the sheath of an XLPE cable by excessive sidewall force at a bend, then the additional use would be made of a bond-pull (a parallel wire bond to which the cable is tied at short intervals), or distributed cable engines (a pair of

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driven wheels or caterpillar tracks in contact with the cable). Cable engines would not be used if the trench is expected to be wet as traction will be lost by slipping. The first cable is carefully lifted off the rollers and placed in position on the floor of the trench. The second and third cables are then pulled in. Having laid the three cables, their spacing is carefully checked and adjusted. Ancillary services are then laid, usually in the corners of the trench, these being small optical fibre P&T cables (pilot and telephone) or small empty ducts for future telecommunication use. The array of cables is then covered (blinded) with the specified thickness of dry CBS or fluid FTB. Robust cover tiles of concrete or plastic are laid to completely cover the blinding. Wide plastic marker tapes are laid overall. Finally the trench is backfilled to ground level with the indigenous soil that had been dug out. In some locations layers of road base and tarmac or concrete are laid to reinstate the surface of the road or street.

4.9.2

Duct-manhole system

Duct-manhole installations are used in urban areas where it is not permissible to open a long length trench. Although the materials are more expensive than a direct buried system, major advantages are:  The project program is more flexible as the installation date of the ducts is isolated from that of the cable delivery. There is freedom to install cable spans in any sequence at any position along the route.  The security measures and risks are reduced.  The joint vaults may be sealed until cable pulling occurs.  A high degree of protection is obtained if the ducts are encased in a duct block formed of concrete or more usually of fluidised thermal backfill.  Cable installation does not require the same amount of skill as is needed for direct burial since the ducts are designed to be within the mechanical design constraints of the cable that is to be installed.  Cable fault repair would involve replacement of duct lengths so that additional splices would not be added to circuit runs.  Splices are accessible for inspection and testing.  Pulling tensions can be more predictable. A duct system is classed thermomechanically as being ‘semi-constrained’. Sufficient clearance is provided in the duct to permit the cable to be pulled-in and to expand laterally when heated. The advantage of lateral expansion is that the sinusoidal and helical patterns that form absorb some of the thermal expansion strain and so reduce a) the axial thrust on the joints in the vaults and b) the sidewall forces on the cable insulation at duct bends. The disadvantages of a duct-manhole system are:  Differences in duct route geometry on either side of the vault apply differential axial thrust on the joint, which can be of high magnitude. The cable clamping

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



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systems in the manholes have to be carefully designed to restrict movement on the splices. The cable metallic sheath is subjected to cyclic bending and the risk of fatigue failure. It is important that the vault constraint system be designed to protect the cable, joint and the support metalwork from buckling and slippage, as the loads generated by a 500 kV 2,500 mm2 cable are high. It is equally important that the cyclic sheath strains are calculated for the particular cable construction and duct clearance to ensure that they fall within the fatigue limit. Thermomechanical duct design for XLPE cables is now understood and design methods are available (EPRI report 1001849 and NSpan software). The possibility exists that in some locations, ground water will fill the ducts and vaults and upon freezing may damage to the cable, joints and duct. This requires to be evaluated as a consequence of the low ambient temperatures that occur in Edmonton region of Alberta. Each repair would usually involve the installation of a span length of cable (manhole to manhole) thereby increasing the value of the inventory of spare materials. The civil installation cost of a duct-manhole system is generally greater than that of a direct buried system The ducts must be tested for blockage or breakage and any defects made good before cables can be installed. This can delay installation. If the pulling tension rises during cable installation, then there is little opportunity for alterations to the cable pulling arrangement to allow the tension to be reduced.

4.9.2.1 Installation of ducts Short lengths of duct are installed. The ducts vary in length according to the preferred duct material and diameter. Small diameter polyethylene (PE) pipes are available on reels of 50 to 150 metre length. The advantage of selecting a long length is that the number of duct joints is reduced, both saving time and cost and in particular reducing risk of damage to the cable jacket when it is pulled in. Large diameter PE pipes will be supplied in straight lengths of 13 metre length, this being dictated by truck length. To reduce cost and time and to improve quality, four of these pipes may be jointed together at ground level and then lowered into the trench. PVC ducts that have a minimum temperature rating are commonly used in Canada. Some ducts are rated as high as 90C. Joints are typically bell and spigot or with plain couplings and glued. Fibre reinforced epoxy (FRE) ducts are rigid and supplied in 6 metre lengths. They are joined together by bell and spigot, scarf joints. Great care has to be taken to ensure that the joints are of good quality and the cable is pulled in the correct direction to reduce the risk of jacket damage. The claimed

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advantages of FRE are that it is a) unlikely to distort at bends and b) less likely to suffer thermal damage in the event of a high energy cable fault, thus permitting the cable to be pulled-out. The three ducts are positioned in the trench at the correct spacing by being fixed to plastic formers at regular spacings. A fourth empty duct may be installed to house a replacement cable should a failure occur and it is not possible to extract the faulted cable. Smaller auxiliary cables ducts are installed to house the pilot and telecommunication cables. Fluidised backfill is poured around the ducts to form a duct block. A mole (or mandrel) is pulled through the duct to ensure that the duct is of correct circular diameter and that there are no obstructions at the duct joints. The duct is also pigged to ensure it is clean. It is good practise to inspect the inside of the duct using a CCTV pipe inspection system. The ducts are sealed to the joint vault (historically named a manhole), which is usually a pre-cast concrete construction. The joints are clamped to a constraint system which in turn is bolted to the walls and floor of the vault. The vault also houses the link box. Alternatively in some installations a temporary joint bay is formed, which after cable jointing has occurred, is backfilled, thereby reducing cost. The disadvantage is that access to the joints is lost for maintenance and more that complexity is required to seal the open duct ends to the cable to prevent entry of the backfill.

4.9.3

Tunnel Installation

Cable tunnels are installed in cities, where:  

It is not reasonably possible either to find a route in roads congested with other services, or to obtain permission to open trenches and stop traffic. Part of the route is required to cross under a major obstacle, such as a wide river.

Tunnels are generally the most expensive form of construction; however they have the advantages of:  Providing independence from weather delays during tunnel construction, cable installation and jointing.  Providing uniform route cross-section geometry to facilitate the installation of the cable, without the need to incur engineering complexity and cost increases associated with route obstructions encountered at ground level.  Providing a protected environment for the cable, free from risk of third party digins and, if the tunnel is designed to be water tight, reduced risk of water damage to the cable, joints and link boxes.  Providing access for the 500 kV Study Project to all parts of the cable at any time of the year for monitoring, maintenance and repair.

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Providing an asset for future use, either in installing more circuits or in replacing or repairing existing cable without need to disturb the ground at surface level. Permitting use of a cable with a lower cost, less robust design of metallic sheath. However, the proposals by the cable manufacturers for the Heartland Project were did not show this.

Deep tunnels are typically built at 20 to 60 metres depth, are circular and are equal to or greater than 3 metres in internal diameter. The thermal resistance is too great to permit heat to dissipate naturally to the ground surface and so forced cooling is employed by drawing cool air down a shaft. The air flows along the tunnel where it extracts the heat from the cable to be vented to atmosphere at another shaft at a typical spacing of 3 to 5 km. A maximum air flow rate of 5 metres per second and a maximum exhaust air temperature of 50oC are typically specified. Acoustic baffles are fitted to reduce cooling fan noise to an acceptable level. A tunnel design study was performed for the 500 kV Study Project showed that for a 5 km long section between shafts it is possible to cool the cables in summer and, by restricting air flow in winter, to limit the minimum joint temperature in the tunnel to 0 oC. This would give a wider choice of joint design and reduce low temperature risk. Shallow tunnels are normally of the ‘cut and cover type’ and are rectangular in cross section. The advantage is that they are lower in cost and prospectively faster to construct as tunnelling machines and deep shafts are not required. It is possible to dissipate some of the cable heat by conductive heat flow to the ground surface, but forced air flow will still be required.

4.9.4

Service experience with different methods of installation at 400 kV and 500 kV

The first major 400 kV cable circuit in Europe was installed direct buried in Copenhagen in 1997[24]. In 2005 a 400 kV 2,500mm2 XLPE cable circuit with a 1,600 MVA power rating was commissioned in a 21 km long deep tunnel under London[32] [33]. The first major 500 kV 2,500 mm2 XLPE circuit was commissioned in 2000 and was in a 40 km shallow tunnel under Tokyo. Table 22 shows that at 400 kV two thirds of the three phase cable lengths are direct buried and these comprise two thirds of the number of installations. One third of the circuit lengths are installed in tunnels. The average three phase circuit length at 400 kV is approximately 10 km for both buried and tunnel installations. System Voltage kV 400 500 TOTAL

Direct buried km # 225.4 20 1.5 1 226.9 21

Duct km 1.5 0 1.5

# 1 0 1

Tunnel km # 109.9 9 114.3 2 224.2 11

All Types km # 336.8 30 115.8 3 452.6 33

Table 22 EHV installation types, three phase cable lengths and number of projects

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There are two significant installations to date at 500 kV one in-service, the 40 km long ShinkeiyoToyosu Project in Tokyo, and one in construction, the 17 km long Shibo Sub Station circuit in Shanghai[2], both of which are installed in tunnels. The average three phase cable lengths for the two tunnel installations is 40 km, this being the same length as would be required for the 10 km scenario in the 500 kV Study Project which has a maximum of four groups of cable. Combining the 400 kV and 500 kV installation statistics, results in 50 % of the project three phase lengths being direct buried and 50 % being in tunnels, with the average length per project being 10 km and 20 km in tunnels. One of the major disadvantages of tunnels, especially if more than one circuit is installed, is fire. An incident on one cable can cause fire or arc damage to adjacent cables or circuits. Whilst XLPE cables are superior to SCFF in this respect, they will still burn under some circumstances.

4.9.5

Service experience with forced cooled systems

The majority of long tunnel installations are cooled by forced air ventilation, for example, the 6.3 km and 5.2 km long, 400kV, 1,600 mm², installations in Germany[25][26] and the 20.6 km long, 400 kV, 2,500mm² installation in UK[31][32][33]. Some tunnels have assisted cooling by the presence of water circulation in one or more pipes separate from the cables with the function of cooling the tunnel air[27][28][29]. The majority of direct buried and duct-manhole systems are naturally cooled. Two notable forced cooled XLPE cable systems are:  direct buried, 400 kV 1,200 mm² installation in Austria[46] which uses lateral water pipe cooling.  400 kV 1,600 mm² system in the Netherlands[48] which uses integral sheath water cooling. Forced cooling is described in Section 3.11.

4.10 Gas insulated lines GIL is considered to be a feasible alternative to XLPE cable for the 500 kV Study Project for installation in a tunnel. At this time, GIL is not considered to be suitable for long length burial in the ground and so is not recommended. Technical information and budgetary bids were sought from suppliers of GIL, however not all responded. GIL was offered for installation in a tunnel and budgetary prices were provided. GIL was not offered for direct burial in the ground. The direct burial method of installation was considered by HPT and CCI to provide the most economical cable and installation costs, for which conventional XLPE cable had been proposed by suppliers. In consequence GIL was not an available alternative and was not evaluated further. Should

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installation in a tunnel be revisited for the 500 kV Study Project, then GIL is recommended to be reassessed as a prospective alternative solution.

4.10.1 Description of GIL GIL (gas insulated lines) are extended lengths of GIS (gas insulated switchgear) busbar, of which there is large worldwide experience up to and including 500 kV. The technical definition[53] of GIL that separates it from GIS is:  where all or part of the HV gas-insulated line is directly buried, or  where the HV gas-insulated transmission line is located, wholly or partly, in an area accessible to the public; or  where the HV gas-insulated transmission line is long (typically longer than or equal to 500m). Figure 64 shows a cross section of the component parts of GIL, which are describes below. A description is also given in Reference[54].

Figure 64. Component parts of a 400 kV gas insulated line

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Conductor The conductor is a hollow busbar normally fabricated from aluminium tube. Example dimensions are 280 mm diameter with an area of 13,000 to 15,000 mm2. A conventional cable has a maximum size of copper conductor of typically 2,500 mm2; the equivalent size in aluminium being approximately 4,100 mm2. Thus GIL possesses 3 to 4 times more conductor area and has the prospective capability of achieving a similar increase in power capacity. The load current of 3,460 A for the 500 kV Study Project rating of 3,000 MW could be carried by one Group of three GIL compared to two groups of conventional cable. Sections of busbar are typically 13 m long. They are connected by electrical plug-in connectors that permit it to axially expand and contract when heated. Thus the generation of thermomechanical forces in the busbar is avoided. Sliding elastomeric seals are provided to contain any particulate contaminants that may be produced and prevent them from entering the gas insulation. The specified permissible temperature rise of the connector usually dictates the maximum current rating of the GIL. Support Insulator The busbar is supported on insulators, as shown in Figure 64. The insulators are cast from a thermosetting material that is formulated to reduce the accumulation of space charge and the attraction of particles. Special diaphragm insulators are used to support the busbar at the ends of a ‘gas section’ and segregate the gas compartments. These insulators are usually conical in shape and have sufficient thickness to withstand the pressure forces when one GIL gas section is depressurised. In the event of an internal electrical fault the diaphragm insulators stop the power arc, (which travels longitudinally under Lorentz forces), from passing into the adjacent GIL section, thereby limiting the length of surface damaged busbar and enclosure. Insulating Gas The insulating gas is either a) 100% SF6 (sulphur hexafluoride) at a pressure of approximately 4 to 5 bar at 20oC, or b) an SF6/N2 nitrogen mixture, for example 20% to 80% with a pressure of approximately 7 bar. The electro negative properties of SF6 gas give high breakdown strength. The gas mixture was introduced to reduce the concentration of SF6 available to leak into the atmosphere. Special gas handling plant is available to store and refurbish the gas mixture for reuse. Enclosure The enclosure is a spirally welded, aluminium alloy tube with typical dimensions of 600-700 mm diameter and 10 mm wall thickness. The thickness is calculated to: 

Provide sufficient low electrical resistance to limit the heat generation and temperature rise to specified limits. A voltage is induced along the enclosure by the magnetic field from the

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primary load current in the busbar. The GIL enclosure is solidly bonded to adjacent phases and to ground at certain positions along the route. The induced voltage drives a ‘circulating current’ along the enclosure. The enclosure has low electrical resistance and so the magnitude of the circulating axial current is high and is of almost equal magnitude to the load current in the busbar. In comparison, the metallic sheaths and shields of conventional transmission class cables are ‘specially bonded’ to prevent current circulation and to avoid the derating effects of unwanted heat. Withstand the internal gas pressure and remain within its elastic limit. Prevent power arc burn-through in the event of a short circuit.

Particle traps are positioned on the floor of the enclosure. The traps locally distort the electrostatic field and so generate dielectrophoretic force, which attracts and traps any conducting particles that may be present. In early designs, the 13 m long sections of GIL enclosure were provided with flanges that permitted them to be bolted together on site. Present designs of GIL enclosure are flangeless, Figure 65 and Figure 66, and are joined together on site by automatic orbital pipe welding machines. This technique achieves economies in material and fabrication and prospectively reduces the risk of gas leakage. The diameters of the busbar and the enclosure are optimised to provide an economical design by:   

Achieving the minimum radial electrical clearance necessary at the limiting electrical design stress at the busbar. The optimum geometry occurs when the diameters are in the ratio of 2.7:1. Increasing the gas pressure to raise the electrical withstand strength of the insulating gas, whilst remaining within the pressure retraining design limits of the enclosure. Ensuring that the resultant dimensions maximise convective and radiant heat transfer.

The inner and outer surfaces of the busbar and enclosure may be treated and coated to improve the electrical withstand strength and heat transfer. For applications in air the outer surface of the GIL enclosure is typically left unjacketed to maximise heat transfer. For direct burial the enclosure would require to be protected by a corrosion resistant layer of the type used on pipe lines, together with a design of cathodic/electrolytic cell protection. Such protection would be required to withstand the enclosure currents (circulating current and short circuit through current).

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Figure 65. Two groups of 275 kV gas insulated line installed in a tunnel Courtesy of Siemens

Figure 66. One group of 400 kV gas insulated line installed on stilts in a substation Courtesy of Siemens

4.10.2 GIL Experience Table 23 shows that the first recorded applications of GIL occurred in 1972 to 1975 and were direct buried. Direct burial was not repeated until 1998 when EDF[55] performed long term tests on buried 400 kV GIL to evaluate its possible use in France as an alternative to overhead line. EDF also performed

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similar tests on conventional direct buried 400 kV XLPE cable. Applications followed in France for conventional 400 kV XLPE cable, but to date have not occurred for buried GIL. Table 23 shows that GIL has generally been selected for special applications that require high power transmission in air in the controlled environment of a substation or tunnel (note: as such these fall outside the original definition of GIL). The number of applications compared to conventional cables and overhead lines is small. The longest circuit length of GIL is 3.25 km, which occurred in a utility owned tunnel in Japan in 1998. Table 23 records the in-progress installation for RWE Transportnetz Strom GmbH at Frankfurt airport in Germany of two 0.9 km long 400 kV GIL circuits. This application is of significance as it is the first true commercial application of direct buried GIL with a length of greater than 0.5 km for 33 years. The commissioning date is planned for the first quarter of 2010. In their internet web press release, a spokesman for RWE said that ‘What we want to do with this pilot project is to try this transmission technology as an alternative to cable solutions. We have already carried out joint tests with the manufacturer on a prototype, which have provided convincing proof of its technical feasibility’. Each GIL conductor matches the rating of one overhead line conductor of 2,598 A. A group of three GIL has a rating of 1,800 MW. 500 lengths of 10.8 m long GIL tube have been delivered to site for the conductor bus-bars to be plugged together and the outer enclosure to be welded in-situ to make gastight joints. Table 23. Details of significant GIL applications Year

Length Circuit Total km km

Voltage

Current

kV

A

SF6 %

GIL Type Installation Method

Application Type

1972

0.414

0.414

230

?

100

buried

commercial

1975

1.45

1.45

138

1250

100

buried

commercial

1975

-

0.58

500

3000

100

buried

commercial

1977

0.13

0.13

138

?

100

buried

commercial

1975 -

0.7 -

1.4 0.14

400 275

820 6300

100 100

tunnel tunnel

commercial test

1998

-

0.07

400

3200

20

tunnel

test

1999

-

0.1

400

4000

20

buried

test

1998

-

0.3

400

4000

10

buried

test

1998

2 x 3.25

19.5

275

2730 5980

100

tunnel

commercial

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Project Na me US, Hudson SS NJ US, Lynchburg Indianapolis US, Ellensburg Washington US, Spy Run SS Indianapolis Germany, Wehr Japan, CRIEPI Test Site Germany, IPH Test Site Germany, IPH Test Site France, EDF Test Site Japan, Shinmeika-




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1997-2000

8 x ~2.1

17.0

400

1200

100

stilts

commercial

2001

6 x 0.4

2.4

220

2000

20

tunnel

commercial

2002

5 x 0.24

1.2

500

4000

60

stilts

commercial

2004

1.64

1.64

400

4000

10

commercial

2010

0.9

1.8

400

2600

?

stilts and covered trench buried

>2010

0.155

0.155

400

?

20

tunnel

Pilot/ commercial commercial

Tokai[56] Saudi Arabia, PP9[57] Switzerland, Palexpo[58] Thailand, Sai Noi[59] UK, Hams Hall[60] Frankfurt Airport Austria, Limberg II[61]

4.10.3 GIL: Advantages and Disadvantages GIL has advantages of: 

    

A low characteristic impedance, because the inductive and capacitive reactances are of similar magnitude and so nearly balance. The impedance of GIL is more ‘resistive’ than that for overhead line (inductive) and underground cable (capacitive) and thus has prospective system design merits for long distance transmission as there is less need for reactive compensation than there is with conventional cable. Suitability for installation in a tunnel, Figure 65, having low risk of fire spread to other circuits. Suitability for installation on stilts in non-public land, Figure 66. High power, voltage and ampacity ratings on a single group of three GIL, for example 4,300 GW, 500 kV and 5,000 A in a force ventilated tunnel application. Near zero external emf. Ease of connection to GIS, thereby avoiding the complexity and cost of either overhead line bushings or cable terminations.

GIL has prospective disadvantages of: 



Doubt about suitability for direct burial, because of: o High mechanical loads in the enclosure and in expansion bellows due to the superimposition on to existing pressure related loads of a) axial thermomechanical loads due to constrained enclosure thermal expansion and b) soil loading. o Increased difficulty of protecting the large diameter, pressure retaining enclosure from corrosion compared to conventional cables. o Risk of bimetallic corrosion between the enclosure and the ground electrode connections. Inability to follow routes requiring changes in direction of small bending radii.

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



  

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Tunnels and shafts need to be designed differently from those required for conventional flexible cables, to a) withstand different and prospectively greater mechanical point loading at some fixing points and b) have shaft access to lower the rigid sections of GIL and to transport them to the point of assembly. Risk of leakage of increased volumes of the greenhouse gas SF6 due to the high volume of long length GIL. SF6 is a ‘green house’ gas with a Global Warming Potential (GWP) of 22,200. To reduce the leakage risk, GIL is segregated into smaller gas sections, enclosures are welded and diluted gas mixtures with reduced concentrations of SF6 are available. Increased complexity of the maintenance necessary to monitor the GIL pneumatic equipment compared with overhead lines and buried cables. The risk of impairment of the dielectric performance due to particulate contaminants. The number of connections between GIL sections in a long route increases the risk and prospective failure rate. Risk of liquefaction of the gas at extreme low ambient temperatures. It was stated by a GIL supplier that SF6 is suitable for operation down to -40oC.

4.11 High Temperature Superconducting Cable Present day funding of research and development into HTSC (high temperature superconducting) cables has produced a succession of technical papers and press releases concerning possible applications. The following account is written to permit the reader to distinguish between the present state of the art and possible future applications with respect to the required reliability and availability of the power system. It will be seen that good progress has been made in the installation of short length, low to medium power HTSC field trials. Approximately 50% of the manufacturers of conventional transmission class cable who were approached with respect to the 500 kV Study Project also have an R&D activity in HTSC cable. These manufactures were not specifically requested to provide bids for HTSC cables and equally none of them offered this possibility as an alternative to conventional cables for the 500 kV Study Project. The feasibility study concluded that significant progress and experience is still to be gained before HTSC cable can be considered to be ready for a major, long length, high power, commercial application such as the 500 kV Study Project. The time until a commercially available and operationally viable high power system becomes available is not predictable at this time.

4.11.1 Superconductivity The metallic conductors used in conventional room temperature cables posses the property of electrical resistance to current flow, which is manifested in the generation of unwanted heat and power loss. Conventional cables and their installation environments are designed to a) reduce the magnitude of the

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heat and power loss by selecting a large conductor size and b) dissipate the heat efficiently to ambient temperature. The present generation of superconducting cable is quite the opposite as it operates at a very low temperature. It is necessary to:  Design the HTSC cable and its installation environment to minimise the inrush of heat into the cable from ambient temperature.  Provide a forced cooled refrigeration system to extract a) the residual heat that enters the cable from the environment, b) the heat that is generated within the HTSC cable by the passage of AC current and c) the heat that is generated by the flow of the coolant. Should an ideal superconductor be found it would exhibit zero resistance, zero heat generation and an unlimited current rating at room temperature. An ideal superconductor would conceptually permit a group of three, small diameter cables, to transmit an unlimited level of power, at low AC voltage, over very long distances, with complete independence of the thermal environment. Should such a superconducting material be found it would revolutionise all electrical equipment and the present way of life. For the latter reasons intensive research into superconductivity has been directed since the discovery in 1911 of the first superconductor, this being the metal mercury in solid form at a temperature of 4.2 K (-268.8oC) i.e. a temperature close to absolute zero at 0 K (-273oC). The physics of superconductivity is described in Tinkham[62].

4.11.2 Low temperature superconductors Mercury was identified to be within a group of superconducting metals and alloys named Type 1 superconductors[63]. Type 1 superconductors are now referred to as low temperature superconductors (LTS). It was found that the superconducting property ceased to exist above certain limits of critical current density, critical magnetic flux density and critical temperature, which limited the superconductor’s use to special applications. LTS materials have critical temperatures in the range of 8 K to 20 K (-265 oC to -253 oC). This temperature is sufficiently low to: 

Restrict the choice of coolant (also named the ‘cryogen’) to liquid helium this being a high cost liquid. Helium is suitable for the extraction of heat by circulation in liquid form in the temperature range between 3 - 5 K (melting point) and 4.2 K (boiling point).



Restrict the choice of thermal insulation to a vacuum vessel containing wrappings of ‘super insulation’ (also named the ‘cryostat’).



Require powered refrigerating equipment to extract heat from the helium cryogen.

One of the most suitable Type 1 LTS superconductors for industrial application was found to be Niobium and some alloys, such as niobium-tin, that being ductile could be formed into tapes and wires. These are suitable for the fabrication of the coils of electromagnets to generate magnetic fields of high strength in high technology applications such as clinical magnetic resonance imaging (MRI), electrical

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power storage devices and atomic particle accelerators. These applications are rendered practical because the coil is contained in a box shaped cryostat of comparatively small dimensions. Power cable applications of superconductivity are perhaps the most difficult to realise[63][64]. The long circuit lengths of typically 0.3 km to 50 km, and their inaccessibility for maintenance, requires containment in an equally long vacuum containing cryostat envelope. Pumps and heat exchangers are required to be distributed along the route, each having high reliability, availability and long life. The first experimental, model superconducting AC cable was constructed in 1968 in London. It was designed to operate at 138 kV and to carry 1,000 MVA. The model was only a few metres in length and was far from a practical component of a transmission system, comprising only one cable, having a limited design of termination and no joints. In 1984 a technical paper reported field trials performed at the Brookhaven National Laboratory on a more advanced single phase cable rig designed to carry 1,000 MVA. In 1983 a technical paper reported a ‘demonstration’ application in which a 50m length of superconducting cable was connected for a period of time to the Austrian National Grid. The development of these LTS cables was not taken further as they could not compete on cost with conventional cables having copper wire conductors and natural heat dissipation.

4.11.3 High temperature superconductors In 1986 superconducting properties were discovered in a ceramic, mixed metal oxide material LBCO (lanthanum barium copper oxide) with a critical current of 38 K ( -235 K). This led to the formulation of the HTS group of superconductors. The critical temperature is taken to be the current at which a one metre length of ‘wire’ has perceptible resistive properties by exhibiting a potential difference of 100 μV. HTSC materials have sufficiently high critical temperatures to permit a useful magnitude of current to be carried at liquid Nitrogen (LN2) temperature. The cost of LN2 as a coolant is approximately 3% that of liquid Helium. This cost driver reinvigorated the R&D of superconducting cable applications. LN2 is suitable for the extraction of heat by circulation in liquid form in the temperature range between 63 K (-210oC), the melting point, and 77.2 K (195.8oC), the boiling point. The maximum permissible current per wire is progressively increased by reducing the temperature below the critical temperature. To achieve a worthwhile cable ampacity rating, the operating temperature should ideally be close to 63 K (-210oC) and the critical temperature of the HTS material should be significantly greater than 77.2 K (-195.8oC). The brittle-like nature of the ceramic superconducting material requires that it be supported either in, or on, a metallic carrier. In this way the bending strain is uniformly distributed and maintained within safe limits when:   

It is wound onto a spool for delivery to the cable factory. The many layers are wrapped onto a cylindrical ‘former’ to construct the cable conductor. The finished cable is wound onto the despatch drum

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

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The cable is installed around the various bends present in the route.

The HTSC superconducting ‘wires’ are actually ribbon shaped. Two types have been developed for power cable prototypes: 

OPIT (oxide powder in tube) wire technology. This produces 1G (first generation) wires). A powder of ‘BSCCO’ (bismuth strontium calcium copper oxide) is used to fill a round silver tube. BSCCO has a critical temperature of ~110 K (-163 oC). The tube is swaged to a small diameter and is then flattened into the shape of a ribbon. The ribbon is heated to high temperature to turn the powder into a ceramic. The swaging process also stretches the wire ribbon to a length in excess of 1,000 m. The dimensions of the ribbon are typically 4 mm wide by 0.2 mm thick (with an area of 0.8 mm2). The majority of HTSC cable prototypes have used OPIT wires, these being reasonably robust and hermetically sealed. The silver encapsulation permits the ribbons to be jointed together by soldering without losing the superconducting properties. The down side is the silver tube is a significant cost item.



CC (coated conductor) technology. This produces 2G (second generation) wires. A buffer layer is deposited onto a thin, wide metallic ribbon. Thin layers of superconducting material are then deposited onto the buffer layer. The superconducting material is ‘YBCO’ (yttrium, barium copper oxide), or similar. YBCO has a critical temperature of ~92-110 K (-181 oC to -163 oC). The tape is slit to a similar 4 mm width to the OPIT wire, but is usually thinner. The advantage of the 2G wire is that its manufacturing cost is lower. The initial disadvantage is that the effective critical current density has been lower than that of the 1G wire, although it is hoped that this will be increased with development.

An individual 1G wire at 77 K is prospectively capable of carrying a current in a practical AC transmission application of 50-100 A, (in comparison the critical current in an ideal DC transmission application may be 100- 200 A). In comparison, a conventional copper conductor wire of 0.8 mm2 in a naturally cooled, buried AC cable would carry approximately 0.8 A and in a forced cooled application ~1.5 A. For the same conductor size, the prospective increase in AC ampacity rating of the HTSC conductor is in the range of 30-60 times. For reasons of overall cable and system design the achieved increase in power in a prototype AC cable has typically been 3-5 times higher than a conventional cable of the same overall size.

4.11.4 Construction of a conceptual HTSC cable As with a conventional cable circuit, a minimum group of three cables is required for an AC transmission system, which can be one three core cable or three single core cables. For the 500 kV Study Project power level of 3,000 MW, the cables are of large diameter and a single core construction is preferred.

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A conceptual 3,000 MW cable design is shown in Figure 67. The cable would have similar dimensions to the 500 kV 2,500mm2 cable described in this report and thus prospectively the despatch reel would accommodate the same typical 700 m length. The HTSC conductor would be required to carry approximately 12,550 A, compared to 1,732 A for the 500 kV Study Project XLPE cable. To take advantage of the high current rating, the system voltage may be reduced from 500 kV to 138 kV. The reduction in voltage permits the thickness of insulation to be reduced. The reduction in thickness provides room for the additional outer HTSC conducting layers and the vacuum filled cryostat. The reduction in system voltage also permits the insulation design stresses to be reduced for both the cable and the joints. The components of one of the three single core HTSC cables are described below Figure 67. A photograph of a 13 kV concentric three phase cable is shown in Figure 68.

Figure 67. Cross section of a conceptual HTSC cable

Former Cable manufacture starts with a flexible tube or cylinder. Inner Quench Conductor A conventional copper wire conductor is stranded (wound) onto the former. The purpose of the quench conductor is to carry the rated short circuit current for the specified circuit breaker clearance time. This

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is because sufficient HTSC wires are applied to take the rated current of 12,550 A only and thus they would lose their superconducting property and would ‘quench’. The quench conductor is placed inside the HTSC conductor to protect it from magnetic induction. Inner HTSC Conductor Sufficient HTSC ‘wire’ ribbons are applied to carry the rated current; for example 170 tapes each carrying an average of say 75 A. The diameter of the former is increased until the magnetic field on the outer layer of HTSC tapes falls to a sufficient value that the 100 A superconducting rating can be achieved (in conjunction with a suitably low LN2 temperature of say 65 K.) Layers of tapes are applied in alternate ‘lay’ directions (left and right hand). The detailed construction of an AC HTSC conductor are important. The AC magnetic field induces eddy currents in the metallic components which must be kept small a) to reduce generation of conventional I2R heating in them and b) to reduce the magnitude of any residual magnetic fields that do not cut the superconductor parallel to its surface as these adversely affect its superconducting properties. Insulation and Shields For the conceptual Study Project HTSC cable a CD (cold dielectric construction is preferred). In a CD cable the whole cable is housed within an LN2 cooled cryostat. A ‘wet’ dielectric has the most experience of use in prototype CD cables. The ‘wet type’ comprises lapped tapes, which are 100% impregnated with pressurised LN2, which performs the role of the dielectric fluid. The tapes are usually PPLP (polypropylene laminated paper). The ‘wet’ CD cable is therefore closely similar to the SCFF cable except the hydrocarbon impregnant DDB (dodecyl benzene) is replaced with LN2. The inner and outer shields are formed of conducting tapes. Inner HTSC Conductor Layers of HTSC ‘wire’ ribbons are applied to form the outer conductor. After the cable system is installed, the three outer HTSC conductors are bonded together and to ground at their ends. The magnetic field from the inner conductor induces a voltage in the outer HTSC conductor, that circulates a current of equal and opposite magnitude. This has the essential benefit of eliminating the magnetic field external to the cable, such the three cables are magnetically isolated and shielded from each other, thereby ensuring that the HTSC tapes only experience a cylindrical field. The secondary benefit is that the surroundings of an HTSC cable experience zero external magnetic field. The downside is that almost twice the number of HTSC wires are required. Outer Quench Conductor A conventional copper wire conductor is applied onto the insulation outer HTSC conductor. This performs the same protective role as the inner quench conductor in carrying short circuit current.

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Sheath Depending upon the particular design of the HTSC cable a ‘sheath’ is applied over the cable core. In the case of a ‘wet’ design of CD cable the sheath may be a permeable tape. In the case of a ‘dry’ design of CD cable, the sheath would be formed of, say, longitudinally welded stainless steel is applied to permit the surrounding LN2 to permeate the insulation and conductors. Annular LN2 Duct The duct is formed by the annular gap bounded on the inner side by the sheath and on the outer side by the cryostat. LN2 is pumped longitudinally along the cable for a distance named a ‘hydraulic cooling section’. The pressure of the LN2 falls along the hydraulic section due to its hydraulic impedance. The maximum inlet pressure is typically 20 bar and the minimum outlet pressure is typically 5 bar. The minimum pressure limit ensures that the insulation is fully impregnated and that the LN2 boiling point is depressed such that N2 gas filled voids cannot form in the insulation. Cryostat The cryostat comprises two stainless steel sheaths with an annular gap in between. The inner sheath is wrapped with ‘super thermal insulation’ comprising multiple layers of thin metalized mylar tape. The purpose of the super insulation is to reflect radiant heat and prevent it entering the cable. The annular gap is evacuated and held at a high vacuum to minimise conductive heat transfer into the cable. A chemical ‘getter’ may be included within the gap to absorb residual gas. Outer Jacket The cryostat is covered with an extruded polymeric layer (for example polyethylene) similar to that applied to conventional cables. The jacket provides protection from abrasion during installation and from corrosion when installed below ground level.

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Figure 68. 13 kV, three phase, concentric HTSC cable construction Courtesy NKT Cables

4.11.5 HTSC Cable System Experience

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records the progress of the development of HTSC cables. The HTSC cable systems have moved from being laboratory test prototypes to ‘field demonstration’ test prototypes. Operational experience is now being gained when connected to either industrial or utility ‘grid’ systems. This progress and the majority, if not all of the projects, have been assisted by funding. The applications fall into two types: 

Low system voltage, three core cable applications, in which a conventional cable application is replaced by an HTSC cable of similar size, but of three to five times power supply capability. The HTSC cable can increase the power rating of a substation in an existing downtown location, when there is no room a) to bring in either multiple conventional cables, or a single higher voltage cable and b) to locate a voltage step-down transformer. Plans were being prepared[65] [66] in 2007 and 2008 for a possible 6 km long demonstration project in down town Amsterdam. An existing 150 kV gas pressure cable in a pipeline with a power rating of 100 MVA was proposed to be replaced by a 50 kV concentric three phase HTSC cable having a 2.5 times higher power rating of 250 MVA. An example of a 13 kV cable with a concentric three phase construction is shown in Figure 68.



Higher system voltage, single core applications, in which the need to install a short length of higher voltage transmission cable can be avoided. The commissioning of the 138 kV, 574 MWA, single core demonstration cables at Holbrook, Long Island Sound, in 2008, is the closest application to the 500 kV 3,000, MW Study Project. Work to develop a 225 kV HTSC was reported in 2000[67], was subsequently discontinued. It is understood that R&D is presently being performed in Japan to produce a 275 kV cable. For an HTSC cable to be considered for a future commercial 3,000 MW application the following would require to be demonstrated: o An increase in cable current rating from 2,400 A to ~12,500 A, o Practical designs of joints that can be quickly assembled and which are suitable for maintenance spares. At present there are none in the demonstration cable. o Ability to scale up manufacturing capacity from supplying a 0.6 km route length to supplying a 10 km route. o Ability of the vacuum filled cryostats to maintain their long term thermal efficiency and to be maintained. o The operational reliability and availability of the LN2 hydraulic circuits together with their distributed pumping and refrigeration equipment.

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Year

Design Current

Length

Power

Voltage

Cable Type Cold or Cores Warm #

Joint

Type

m

MVA

kV

A

1999

50

400

115

2,000

WD

1

yes

test

2001-2007

30

27

12.4

1,250

CD

3 con

no

grid demo

2001-2003

30

104

30

2,000

WD

1x3

no

grid demo

2002

100

115

66

1,000

CD

3

no

test

2003-2005

500

133

77

3,000

CD

1

no

test

2005-2006

100

50

23

1,260

CD

3

yes

test

2006

300

69

13.2

3,000

CD

yes

grid demo

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3 con

Application Location

Italy, Milan HV lab[68] US, Carrolton, Georgia Denmark, AMK SS, Copenhagen[69] Japan, Yokosuka test site[70] Japan, Yokosuka test site[71] Korea, KEPCO test centre[72][73] US, Bixby, Columbus, Ohio[74] [75]




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2006-2009

350

48

34.5

800

CD

3

yes

grid demo

2008

610

574

138

2,400

CD

1x3

no

grid demo

2010-2011

300

62

13.8

3,000

CD

3 con

no

grid demo

2011

1,760

48

13.8

2,000

CD

3 con

yes

grid demo

US, Albany, NY US, Holbrook, Long Island Sound[76] [77] US, Manhattan, NY City US, LabarreMetairie SS, Louisiana, New Orleans

Table 24. Details of some HTSC cables and applications Notes: CD: cold dielectric; a cable in which the conductor(s) and insulation is cooled to LN2 temperature. WD: warm dielectric; a cable in which the inner conductor contains a LN cooling duct and is surrounded by the cryostat. Everything outside the cryostat is nominally at ‘room’ temperature. the insulation is applied over the cryostat and so is named a ‘warm dielectric’. Cores: 1: one single core cable manufactured for laboratory test. 1 x 3: three single core cables usually manufactured for a demonstration trial application connected to a utility or industrial ‘grid’. 3: a three core cable in which the three cores are housed within a common cryostat. 3 con: a single cable comprising three concentric phase conductors separated by annular layers of insulation. ‘Triax’ is one trade name.

4.11.6 Installation of a conceptual HTSC cable system for the Study project To provide n+1 redundancy for maximum reliability and availability it is proposed that the cables would be installed as shown in Figure 69, Figure 70 and Figure 71:    

Each cable to be cooled by containment in an annular LN2 duct. A central conductor duct is not to be used. This simplifies the design of the cable and avoids the need for joint designs to have complex LN2 stop and feed capabilities. Each single core cable to have its own separate LN2 cryostat return pipe, instead of a shared return through a parallel cable. If one cable is damaged, the other two will be retained in sound condition. Each cable and return pipe to be housed in a separate trough to permit access without disturbing the adjacent cables. HTSC cables are thermally and magnetically independent and so an increase in spacing is permissible. Two groups of three cable to be provided per circuit, each normally carrying half load and only taking the full 3,000 MW load in a contingency situation. This is the arrangement recommended for the 500 kV Study project. The HTSC cable has the additional advantage that the symmetry

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of their spacing is not critical. If a single cable should be taken out of service, then its place can be taken by one cable from the adjacent Group of Cables. This can be repeated three times, thereby maximising n+1 redundancy. The resulting 39 m width of the swathe, Figure 71, required for two circuits of 138 kV HTSC cable, each comprising two Groups of cable is closely similar to the 40 m width required for the conventional 500 kV cable shown in Figure 78. No advantage in the swathe width of an HTSC installation for the 500 kV Study Project is envisaged. Conceptual HTSC cables do have a prospective advantage for the 500 kV Study Project in that they are thermally independent of their environment. The crossing of route obstructions at depth would not have the thermal limitations experienced by conventional cables.

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h

a l

i

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To provide appropriate mechanical protection and to provide sufficient access to the cables to permit removal and replacement of cables, the following dimensions are proposed: Dimension a b c d e f g

mm 200 150 200 200 50 50 1000

h i j k l

75 75 75 75 500

Figure 69. Conceptual arrangement of an HTS cable in buried trough

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To provide appropriate mechanical protection, the following dimensions are proposed: Dimension a b c d e

mm 1000 3050 500 1000 1500

Figure 70. Conceptual cross section dimensions of a HTSC buried, three phase group / trench arrangement

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To allow physical separation between Groups of Cables and sufficient clearances for installation, the following dimensions are proposed: Dimension

mm

a b c d e

3000 2000 10000 3000 10000

f

39000

Figure 71. Conceptual installation swathe dimensions for a HTS cable trenches

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ESTIMATES OF RELIABILITY. 

Expectations of reliability Utilities throughout the world are now purchasing XLPE cable systems at voltages up to the highest EHV levels, which demonstrates their confidence in the reliability of this technology.



Quality assurance and testing, care and maintenance The 500 kV underground cable system can be expected to give reliable service, subject to:  Successful completion of proving tests before supply.  Quality control test programs during manufacture and installation.  Protection of the cable system from third party damage throughout its service life. The objective in the design, Proving Testing, manufacturing and installation of a 500 kV cable system is to eliminate failures in-service. After site assembly, a commissioning test is performed with the objective of detecting failures due to installation damage, or incorrectly assembled components. A high AC voltage withstand test is applied for 60 minutes; this test is specified in IEC 62067[1]. Although not yet required by IEC specifications, it has become normal practice for utilities to specify that partial discharge measurements be performed at each joint and termination. This is a non-destructive test to ensure that no detectable incipient electrical activity is present. Any faults detected are repaired, or replaced, before the cable system is accepted into service. Statistics show that a significant proportion of cable failures are due to third party ‘dig-ins’. Adequate protection measures must be incorporated into the design of the installation. Adequate surveillance and maintenance must be conducted throughout the service life. The incidence of third party damage can then be expected to be low.



Availability of transmission line It is a requirement of the design of the 500 kV Study Project that n-1 redundancy exists, such that either of the two circuits can carry the peak load of 3,000 MW as a contingency operation in the event that the other circuit is unavailable. For this redundancy to be effective, the risk of coincident failures on parallel transmission lines must be low and the repair time short. This report gives the failure rates and repair times of the cable system, based on published data, so that a statistical analysis may be performed in the recommended next steps.

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The reliability assessment for the complete transmission system must be performed to include the other components, which include overhead lines, transition station components and substation termination components.

5.1

Repair times for 500 kV XLPE cable

The failure rates reported by CIGRE[49] only include failures which either result in an instantaneous failure leading to automatic disconnection or an occurrence requiring subsequent unplanned outage, it can therefore be assumed that if any failure occurs then an unplanned outage will occur that will require to be repaired. The average outage repair time given in CIGRE TB 379[49] for the 220 kV to 500 kV category is 25 days with a difference in repair times of up to 14 days (Page 41 therein). However, for the climate during the winter period in the Edmonton region of Alberta, the repair times would be extended by the need for additional measures to mitigate the effects of the cold temperatures. This would typically be expected to extend the repair times by approximately one week during the period from October to April. For the Edmonton region of Alberta the average outage repair time should therefore be increased to 29 days. It is likely that faults which involve the primary insulation will take significantly longer to repair than affect only the cable jacket or external protection of accessories. Further details of cable system repairs are given in Section 7.22.

5.2

Fault statistics for underground 500 kV XLPE cable

In this section and in Section 5.3 fault statistics are given separately for XLPE cable and overhead line. A comparison has not been performed as the data upon which the cable failure statistics has been based is too small in number, and for too short a duration, to be trustworthy. It is expected to be several more years before sufficient failure data becomes available for reliable analysis.

5.2.1

Cable system fault statistics

The cable fault statistics are derived from those published by CIGRE in Technical Brochure number 379[49]. These are based a cumulative 220 kV to 500 kV cable circuit length of 1,388 km collected in a limited worldwide survey. This is significantly smaller than the 54,381 km length of overhead line in the same voltage category installed in Canada alone. The authors of CIGRE 379[49] state on page 10 ‘That caution should be used when interpreting failure rates, particularly in the case when the size of the data population is small……….Failure rates are mean failure rates and it is not appropriate to use them to calculate mean time between failures and availability of circuits’. Further commentary on the activities of Cigre Study Committee B1 is given in the “Jicable 07 paper[78], this includes the statement that, “There is still limited service experience with EHV XLPE cable systems. The design,

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manufacturing methods and materials employed in joints and terminations differ significantly amongst manufacturers. Consequently the service experience from any particular system cannot necessarily be taken as a guide to the likely service experience of other systems.” Thus whilst the number of failures in the following Table 28, Table 29, Table 30, and Table 31 have been extrapolated from the CIGRE 379 data, they cannot be regarded as being anywhere near as accurate as the data relating to overhead lines. Study Committee B1 of the international organisation CIGRE collects and analyses the service experience of cable systems and their component parts. The most recent work was prepared by working group WG B1.10, which was published by CIGRE in April 2009 as Technical Brochure 379[49], ‘Update of service Experience of HV Underground and Submarine Cable Systems’. A questionnaire was prepared by the members of the working group and issued to 25 regions world wide. Seventy three positives responses were received from 24 regions, which comprised returns from 73 utilities. The questionnaire collected data up to the end of the year 2005. The categories of interest to the 500 kV Study Project are a) failures in AC land cables in the voltage range of 220 kV to 500 kV of the extruded type, these being XLPE and PE cables, b) failures in all types of land cables in the voltage range of 220 kV to 500 kV in categories of installation type and d) repair outage times in the voltage range of 220 kV to 500 kV for extruded cables. The trend in AC failure for XLPE systems cable systems with age of failed components is illustrated in a bar chart in Figure 12 on page 32 therein, in four voltage categories. The Executive summary of the above Technical Brochure states on page 3: ‘That between the years 2000 and 2005, almost all installed AC cables have been of the XLPE or SCOF cables with XLPE being the preferred type. At voltages below 220 kV, more than 90% of the cable circuit length installed from 2001 to 2005 was of the XLPE type. For voltage levels above 220 kV SCOF (SCFF) cables still account for more than 40% of the cables installed’. The failure rates for XLPE cable system components in the voltage range of 220 kV to 500 kV are given in Table 11 on page 30 of the CIGRE publication[49] and are summarised in Table 25 below. Component Cable (all failures) Joints (all failures) Terminations (all failures)

Failure Rates Per year per 100cct.km1 Per year per 100 joints Per year per 100 terminations

0.133 0.048 0.050

Table 25 CIGRE failure rates of components in 220 kV to 500 kV XLPE cable systems

The cable failure rates are given by CIGRE in units of failures per year per 100cct.km. As most of the cable circuits analysed by CIGRE could be expected to consist of one Group of Cables, the CIGRE findings are taken to be equivalent to failures per year per Group of Cables, i.e. three single core cables.

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Table 26 (Table 11 in TB 379[49]) shows the distribution of faults by cause for each component of the extruded 220 kV-500 kV AC land cable system. Approximately half the faults are ascribed to internal causes, and half to external causes. An internal failure is attributable to the cable or component, and an external failure is attributable to external parameters (e.g. third party interference, subsidence, etc). Component Cable (internal) Cable (external) Cable (all failures)

Failure Rates Per year per 100cct.km Per year per 100cct.km Per year per 100cct.km

0.067 0.067 0.133

50% 50% 100%

Joint (internal) Joint (external) Joints (all failures)

Per year per 100 joints Per year per 100 joints Per year per 100 joints

0.026 0.022 0.048

54% 46% 100%

Terminations (internal) Terminations (external) Terminations (all failures)

Per year per 100 terminations Per year per 100 terminations Per year per 100 terminations

0.032 0.018 0.050

64% 36% 100%

Table 26 Failure rates of components in 220 kV to 500 kV XLPE cable systems by cause

5.2.2

Application of fault statistics to the 500 kV Study Project scenarios

Because of the particular features of the 500 kV Study Project, the following conditioning factors could be applied to the internal failure rates for accessories (joints and terminations) given in Table 26. 

1.3 (30%) to allow for the possibility that the failure rate in the higher electrically stressed, large conductor, 500 kV Study Project is likely to be higher than the average in the 220 kV-500 kV category.



1.3 (30%) to allow for the possibility that the failure rate may be increased as a result of the high operating temperature range and low winter ambient temperature in the Edmonton region of Alberta.

When the above factors have been applied, the conditioned failure rates are as shown in Table 27.

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Component Cable (all failures) Joints (all failures) Terminations (all failures)

Failure Rates Per year per 100cct.km Per year per 100 joints Per year per 100 terminations

0.133 0.066 0.072

Table 27 Conditioned failure rates of components in 220 kV to 500 kV XLPE cable systems Both the above unconditioned and conditioned failure rates have been applied to the eight scenarios considered for the 500 kV Study Project. The results are given in the following tables of failure rates (Table 28, Table 29, Table 30 and Table 31). In each of the tables of failure rates for the study scenarios, the failure rates are also given for one Group of Cables. Each group is equal to the route length of underground cable.    

Stage Total number of Groups of Cables

Table 28 and Table 30 are based on the unconditioned failure rates in Table 25. Table 29 and Table 31 are based on the conditioned failure rates in Table 27. Table 28 (unconditioned) and Table 29 (conditioned) show the number of failures for one year in-service. Table 30 (unconditioned) and Table 31 (unconditioned) give the total number of failures over a 40 year service life. One Group of Cables

1A-10

1B-20

2A-10

2B-20

3A-10

3B-20

4A-10

4B-20

n/a

n/a

1

1

n/a

n/a

1

1

#

1

1

4

4

2

2

3

3

2

2

Route length

km

10

20

10

20

10

20

10

20

10

20

Cable failures

#

0.01

0.03

0.05

0.11

0.03

0.05

0.04

0.08

0.03

0.05

Joint failures

#

0.03

0.05

0.10

0.21

0.05

0.11

0.08

0.16

0.05

0.11

Termination failures

#

0.00

0.00

0.01

0.01

0.01

0.01

0.01

0.01

0.01

0.01

Cable system failures

#

0.04

0.08

0.17

0.33

0.08

0.17

0.13

0.25

0.08

0.17

Table 28 Unconditioned cable system failure rates for the study scenarios for one year in-service

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1

1

1A-10

1B-20

2A-10

2B-20

3A-10

3B-20

4A-10

4B-20

n/a

n/a

1

1

n/a

n/a

1

1

4

4

2

2

3

3

2

2

Route length

km

10

20

10

20

10

20

10

20

10

20

Cable failures

#

0.01

0.03

0.05

0.11

0.03

0.05

0.04

0.08

0.03

0.05

Joint failures

#

0.04

0.07

0.14

0.29

0.07

0.15

0.11

0.22

0.07

0.15


#

0.00

0.00

0.02

0.02

0.01

0.01

0.01

0.01

0.01

0.01


#

0.05

0.10

0.21

0.42

0.11

0.21

0.16

0.31

0.11

0.21

Table 29 Conditioned cable system failure rates for the study scenarios for one year in-service Table 28 (unconditioned) and Table 29 (conditioned) give the total number of failures for one year inservice and show that: 

In one year the likelihood of failure of a single Group of Cables is low, the unconditioned value being 0.04 per year (equivalent to one failure in a 25 year period) for a single Group of Cables, 10 km in length. This is shown in Table 28.



In one year the likelihood of one failure in all of the parallel Groups of Cables together is increased in proportion to the number of Groups of Cables, thus extrapolating from the previous example, the lowest likelihood of failure for the 500 kV Study Project is 0.08 per year (equivalent to one failure in a 12.5 year period) for the 10 km length with two Groups of Cables in parallel, again without the conditioning factor applied. This is shown in Table 28, Scenarios 2A-10 (Stage 1) and 4A.10 (Stage 1). .



The numbers of failures also increase with the route length and if the conditioning factor is applied. The highest is 0.42 per year (equivalent to one failure in 2.4 year period) for four Groups of Cables, 20 km route length, with the conditioning factor applied. This is shown in Table 29, Scenario 1B.20. .

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1

1

1A-10

1B-20

2A-10

2B-20

3A-10

3B-20

4A-10

4B-20

n/a

n/a

1

1

n/a

n/a

1

1

4

4

2

2

3

3

2

2

Route length

km

10

20

10

20

10

20

10

20

10

20

Cable failures

#

0.53

1.06

2.13

4.26

1.06

2.13

1.60

3.19

1.06

2.13

Joint failures

#

1.04

2.13

4.15

8.52

2.07

4.26

3.11

6.39

2.07

4.26


#

0.12

0.12

0.48

0.48

0.24

0.24

0.36

0.36

0.24

0.24


#

1.69

3.32

6.76

13.26

3.38

6.63

5.07

9.95

3.38

6.63

Table 30 Unconditioned cable system failure rates for the study scenarios for 40 years in-service


One Group of Cables 1

1

1A-10

1B-20

2A-10

2B-20

3A-10

3B-20

4A-10

4B-20

n/a

n/a

1

1

n/a

n/a

1

1

4

4

2

2

3

3

2

2

Route length

# k m

10

20

10

20

10

20

10

20

10

20

Cable failures

#

0.90

1.80

2.13

4.26

1.06

2.13

1.60

3.19

1.06

2.13

Joint failures

#

1.75

3.60

5.70

11.71

2.85

5.86

4.27

8.78

2.85

5.86


#

0.20

0.20

0.69

0.69

0.35

0.35

0.52

0.52

0.35

0.35


#

2.85

5.60

8.52

16.66

4.26

8.33

6.39

12.49

4.26

8.33

Table 31 Conditioned cable system failure rates the study scenarios for 40 years in-service Table 30 (unconditioned) and Table 31 (unconditioned) give the total number of failures over a 40 year service life and show that: 

Over a 40 year period the unconditioned likelihood of failure of a single Group of Cables is 1.69 for a single Group of Cables, 10 km in length. This is shown in Table 30.



The lowest likelihood of failure for the 500 kV Study Project is 3.38 for the 10 km length with two Groups of Cables in parallel, again without the conditioning factor applied. This is shown in Table 30, Scenarios 2A-10 (Stage 1) and 4A.10 (Stage 1). (As it is envisaged that the Stage 1 cable systems would be augmented by the Stage 2 cables at some point during the 40 years, this figure would have to be increased to represent the whole project)



The numbers of failures increase with the route length and if the conditioning factor is applied. The highest likelihood of failure for the 500 kV Study Project is

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16.66 for four Groups of Cables, 20 km route length, with the conditioning factor applied. This is shown in and Table 31, Scenario 1B.20.

5.2.3

500 kV Study Project fault rate

Based on the information in Section 5.2.2 and the published data[49] therein, the estimated numbers of faults per year which that occur in the 500 kV Study Project are given below for different numbers of Groups of Cables.

One ‘Groups of Cables’ in operation: Two ‘Groups of Cables’ in operation: Three ‘Groups of Cables’ in operation: Four ‘Groups of Cables’ in operation:

5.2.4

10 km 0.04 to 0.05 0.08 to 0.11 0.13 to 0.16 0.17 to 0.21

20 km 0.08 to 0.10 0.17 to 0.21 0.25 to 0.31 0.33 to 0.42

faults per year faults per year faults per year faults per year

Types of cable faults

Table 32 records the number of faults reported in all types of AC land cable (XLPE, SCFF and HPFF) in the voltage range 220 kV to 500 kV. Care is required in the interpretation as the reported quantities of cable and accessories are not given. CIGRE TB 379[49] reports in a fault analysis on page 47 therein: ‘That at all voltages and for all cable types, buried cable systems are about ten times more likely to be damaged by external conditions than cable systems installed in ducts or tunnels’. In practice the ratio would be expected to be smaller at the EHV voltages as the buried cables are likely to be buried deeper and to be protected by more robust materials. CIGRE TB 379[49], Table 10c, shows that at 220 kV to 500 kV for all types of cable and for all types of installation 57% of the faults were internal and 25% were due to third party damage, 17% were attributable to other unspecified external causes. Installation Type Internal Direct buried Ducts Tunnels Troughs Bridges In-air All installation types

59 5 7 2 0 1 74

Numbers of Faults Third Party Other External Causes 28 17 3 2 0 2 2 2 1 0 0 0 34 23

Total 104 10 9 6 1 1 131

Table 32 Numbers of faults in all types of 220 kV-500 kV AC land circuits by installation type

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5.3

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Overhead line fault statistics

The Line-Related Sustained Forced Outage rate for 500 to 599 kV overhead lines is given in Appendix Section 1 which has been abstracted by HPT from Canadian Electricity Association publication, Forced Outage Performance of Transmission Equipment 2007 [79]. This data is based on the performance of a cumulative length of 9,853 km of 500 to 599 kV transmission lines in Canada alone. The overhead line rate is for sustained forced outages of duration one minute or more and excludes automatic re-closure events. The rate is 0.2366 events per 100 km per year. For the purpose of this report these events are referred to as failures. The mean duration of each Line-Related Sustained Forced Outage is 4.9 hours. The total number failures for each scenario for both one year in-service and for forty years in-service is shown in Table 33 and Table 34 respectively.

Stage

1A-10

1B-20

2A-10

2B-20

3A-10

3B-20

4A-10

4B-20

n/a

n/a

1

1

n/a

n/a

1

1

Number of OHL circuits

#

2

2

2

2

2

2

2

2

OHL Route length

km

55

45

55

45

55

45

55

45

OHL failure rate per 100km per year

#

0.2366

0.2366

0.2366

0.2366

0.2366

0.2366

0.2366

0.2366

OHL failures

#

0.26

0.21

0.26

0.21

0.26

0.21

0.26

0.21

Table 33 OHL failure rates for the study scenarios for one year in-service

Stage

1A-10

1B-20

2A-10

2B-20

3A-10

3B-20

4A-10

4B-20

n/a

n/a

1

1

n/a

n/a

1

1

Number of OHL circuits

#

2

2

2

2

2

2

2

2

OHL Route length

km

55

45

55

45

55

45

55

45

OHL failure rate per 100km per year

#

0.2366

0.2366

0.2366

0.2366

0.2366

0.2366

0.2366

0.2366

OHL failures

#

10.41

8.52

10.41

8.52

10.41

8.52

10.41

8.52

Table 34 OHL failure rates for the study scenarios for forty years in-service The Canadian Electricity Association publication also gives statistics for line related transient forced outages of duration less than one minute which only covers automatic reclosure events, the rate being 0.8718 events per 100 km per year. These events have been excluded from the study because the overhead line is still available for service.

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6

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OVERVIEW OF POTENTIAL ENVIRONMENTAL EFFECTS OF UNDERGROUNDING

An environmental overview has been prepared by the HPT and is given in full in the Appendix, Section 11. The overview outlines some of the potential effects on biophysical components related to underground transmission lines. As is the case with any project, detailed design and the environmental context are important for understanding and describing specific potential effects related to an underground transmission development. Discussions must occur with appropriate regulators relative to any underground transmission development better to identify appropriate mitigations and regulatory expectations. The overview also considers the environmental impact of the installation activities and of the installed plant of a non-specific 500kV high capacity underground transmission project. The document describes the following components of the project: 1. 2. 3. 4. 5. 6.

Transmission line – trenching Joint bays Concrete encased duct banks Transmission line – Horizontal Directional Drilling Transition stations Ongoing operations and maintenance.

The document then continues to address the potential environmental effects and mitigation measures under the following headings: Terrain and Soils Soil disturbance and contamination from leaks and spills during construction. Vegetation and Wetlands Destruction of native and sensitive vegetation during construction, introduction of non native species, disturbance of wetland and riparian vegetation which might be difficult to reclaim. Potential soil erosion when vegetation is removed. Alterations to drainage patterns and contamination from leaks and spills during construction. Wildlife and Wildlife Habitat Habitat destruction during construction and maintenance, changes in direct and indirect mortality risk due for example to the clearing of forested areas increasing the line of sight. Effect on nesting and rearing sites due to vegetation clearance and trenching.

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Surface Water, Fish and Fish Habitat Introduction of sediment into watercourses. Changes to water quality arising from leaks and spills during construction. Introduction of HDD drilling mud due to inadvertent release during drilling and the introduction of bentonite as a result of duct failure. Groundwater A shallow groundwater table may result in flooded trenches. Changes to hydraulic dynamics of springs are possible where the cable trench encounters the spring discharge area. Under each of the above headings the potential environmental effects are given and selected proposed mitigation measures are presented.

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7

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PRELIMINARY 500 KV UNDERGROUND CABLE SCOPING STUDY

A preliminary underground cable scoping study was conducted for the 500 kV Study Project in order to:  Provide the outline installation cross-section dimensions necessary for the HPT to study and cost. This could then be performed concurrent with the cable manufacturers’ design work.  Provide a point of reference for the manufacturers’ design proposals to ensure that they had understood the requirements. This preliminary scoping study has been based upon the same design parameters as have been provided to prospective cable suppliers for the Heartland Project. Installation cross sections have been prepared for the following:  Duct manhole system  Direct burial of cables  Deep tunnel  Cut and cover tunnel

7.1

Description of the cable type used for the preliminary scoping study

500 kV cables with high power transmission capability have been supplied using either extruded XLPE insulation or fluid filled PPL insulation. For this scoping study XLPE cable has been used. The reasons for this choice are:  It is available from many suppliers  It is perceived as the technology of choice for the future, with manufacturers phasing out their manufacturing capability for SCFF cable – thus spares and resources to repair XLPE cable are more likely to be available for the lifetime of the circuit The selected XLPE cable constructional details and dimensions are shown diagrammatically in Figure 72.

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500 kV Cable used for preliminary scoping study 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, Smooth aluminium sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

Diagrammatic only Item 1 2 3 4 5 6 7 8

Details Oxidised copper conductor Conductor binder Extruded screen XLPE Insulation 32mm nom Extruded screen Water-blocking cushioning tapes Aluminium shield (welded) Polyethylene Jacket with semi-conductive coating

Nominal diameter (mm) 64.0 68.0 132.0 135.0 137.5 141.0 152.0

Approximate weight 39 kg/m Figure 72: Construction and dimensions of Scoping Study 500 kV, 2500 mm², XLPE cable

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The following conductor type has been used for the scoping study:  2,500 mm² copper.  AC resistance typical of conductors with oxidised wires.  constructed using several stranded segments (Milliken construction). The reasons for the use of this material, size and construction of conductor for the scoping study are: 





2,500 mm² represents the maximum conductor size that is available from most manufacturers. (Some manufacturers have designs and/or manufacturing capability for 3,000 mm² or possibly 3,500 mm² but little or no service experience exists.) If aluminium conductors are selected then at least three cables per phase would be required for each circuit of the 500 kV Study Project. This would not be economically advantageous. For the 500 kV Study Project the ampacity requirements are such that the use of plain copper wire conductors is likely to result in a requirement for three cables per phase, particularly for some of the obstruction crossings. Ampacity can be increased by the use of coated wire. Most manufacturers are able to offer some kind of coated wire conductor design. The designs available are oxidation and enamelling. Conductors with enamelled wires generally have lower resistance than those with oxidised wires but may not be offered by all manufacturers or otherwise inappropriate for the 500 kV Study Project. A segmental construction is offered by virtually all manufacturers for large conductor sizes as it is significantly more efficient than non-segmental designs.

An insulation thickness calculated to give an electrical stress at the insulation shield (i.e. the outer shield) of 7 MV/m at 525 kV between phases has been selected. This design stress has been selected as:  It is the stress experienced by the accessories and is considered to be reasonably safe with current technology.  It is around the average stress that most manufacturers were believed likely to offer.  It is not so low as to make the cables unfeasibly large for transportation to site. XLPE cables are frequently constructed using one of the following methods to prevent radial water penetration and to enable short circuit currents to be carried:  A longitudinally welded aluminium sheath.  A corrugated seamless aluminium sheath.  A copper wire screen included under a lead sheath.  A copper wire screen included under an aluminium or copper foil laminate.  A copper wire screen included under a longitudinally welded stainless steel sheath.

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

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A copper wire screen included under a longitudinally welded aluminium sheath.

A longitudinally welded aluminium sheath without a separate copper wire screen has been used for the scoping. This construction has been selected for the scoping study as:  This type of construction is available from several suppliers.  It gives a reasonably high degree of water penetration resistance – required for important cable circuits.  It results in a cable with a relatively small overall diameter when compared to cables with corrugated sheaths or a combination of copper wire screen and metallic sheath and thus is considered to be representative of a possible eventual solution.  This type of cable is offered as being suitable for all installation methods, rigidly cleated in air, flexibly cleated in air, in unfilled ducts, and direct buried in the ground. Separate designs are thus not needed for this scoping study.  The sheath losses from this design are relatively high compared with other types thus not giving overly optimistic results.  The cable design used for this scoping study has a sheath thickness of 1.75mm. This has been selected as being sufficient for the short circuit current level of 40kA for 1 second. The base case cable for this scoping study has an outer jacket made of extruded medium or high density polyethylene (MDPE or HDPE). This has been selected as:  It available from all manufacturers and it has been proven in-service to give a sufficiently high resistance to abrasion, cracking and water penetration. (For use within tunnels, polyethylene is commonly perceived to have too great a flammability, and hence other materials are often used).

7.2

Cable installation options Installation configurations have been prepared for buried cables in both  

A duct-manhole, system: Installed directly in the ground:

 A duct-manhole, system offers the following advantages:  This type of installation is common in North America  The cables can be installed more quickly than in a direct buried system  It offers good protection against mechanical damage from external influences as the cables are in ducts embedded in concrete.  In the event that a cable should need to be replaced then the cable can be removed and replaced a lot easier than if it were direct buried

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 Installing cables directly in the ground offers the following advantages:  The ampacity is generally greater than for a ducted system.  Direct burial gives more protection against the effects of thermomechanical movements  Fault location is easier in a direct buried system as the entire jacket is in direct contact with the backfill. Any electrical perforation of the jacket can be detected by external, above ground, tests.  A failure of a directly buried splice is unlikely to affect the adjacent phases whereas a failure in a manhole may damage all the cables and equipment inside.

7.3

General installation configuration To achieve the required ampacity of 3,465 amps (3,000 MVA at 500 kV) for each circuit, two cables per phase will be required for all the installation configurations described in this scoping study. Each cable would then be required to carry 1,733 amps. Each circuit would be configured as two Groups of Cables. Each Group of Cables would consist of three single core cables and be installed in a separate trench. This is shown schematically in Figure 73.

Figure 73 Scenario 1 In Figure 73 two circuits are depicted between Station A and Station B. Each of the black dotted lines represents one Group of Cables underground cable There could be one or more obstacles on the route which require the use of three cables per phase. If it is not possible to achieve the required ampacity along the whole of the route with two cables per phase, then three cables per phase will be required.

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A flat, horizontally spaced configuration has been selected for the scoping study. This has been selected because  it offers better ampacity than trefoil or vertically spaced arrangements  it offers better access to the cables should a repair be necessary Different types of cable formations are shown in Figure 38 and Figure 39.

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7.4

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Preliminary scoping study: duct-manhole system

7.4.1

Configuration of cables in ducts

Based on installation primarily in agricultural land a trench cross section typically as shown below is proposed:

Reinstatement as required to match original Ground surface

Compacted excavated material (if thermally suitable) including replacement of topsoil to landowners requirements

Warning tape (as required) Warning tapes placed on top of full area of ductbank

Thermal Backfill 6mm poly placed on top of full area of ductbank Power Cable ducts

Auxiliary ducts

Concrete

d

e

e

d

Figure 74: Preliminary duct block arrangement

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To achieve the required ampacity, the following dimensions have been calculated: Dimension a b c e d p q

mm 250 250 200 500 250 900 1100

Dimensions for Figure 74

7.4.2

Duct for scoping study The following outline duct dimensions and requirements were advised to HPT as the basis for installation costing. Power cable ducts are Nominal Size 8 (OD 219 mm/8.625 inch), Schedule 40 Polyethylene conduits (minimum ID 199 mm/7.846 inch).  These are polyethylene conduits, with a layer of semi-conductive material internally to facilitate fault location. At each conduit join there is a semi-conductive path to the outer surface. This is a non standard duct construction and would require custom manufacture.  Ducts have solid walls; ducts with corrugated walls containing an air gap should not be used.  Any joints must be correctly aligned and free from sharp edges or burrs.  Ducts shall be substantially circular and capable of passing a mandrel of diameter 6mm less than the internal diameter.  Ducts shall be clean of soil, sand, stones or other debris, and shall be effectively plugged and sealed.  A drawstring shall be installed in each duct. Auxiliary ducts shall be 100 mm PVC conduit

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7.4.3

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Trench filling

It is vital that the thermally resistivity of the soils and other material surrounding the cables is controlled. The details of the trench filling materials for this scoping study are as follows: The backfill placed above the concrete ductbank shall be of the fluidised thermal backfill type or selected sand/gravel or crushed rock and shall have a dried out thermal resistivity no greater than 0.9 K.m/W. [For information, in the absence of specific local measurements, a value of 0.9 K.m/W has been taken for the backfill in all of the cable ampacity calculations, having been abstracted from a) IEC 60267[80] for the typical values in Canada, there being no recognised national values and b) the value given in the technical specification[81] for the recent 240 kV cable installation in Edmonton for native soil resistivity for depths of less than 3.5 m.]  Where the route crosses agricultural land the top of the thermal backfill must be no less than 900 mm below the surface to avoid disturbance by agricultural equipment (this would require to be verified for Edmonton farming conditions).  The thermal backfill placed above the concrete ductbank forms part of the thermal design of the circuit; the warning tapes or tiles placed above thermal backfill must extend the whole length and width of the route.  This layer can be replaced with concrete if more economical. Trench filling above the thermal backfill and to either side of the trench must have a thermal resistivity of not greater than 0.9 K.m/W[80,81] and not greater than 3.0 K.m/W[82] when fully dried out. (The latter values would need to be verified by taking measurements and samples in situ in trial holes dug along the route when selected).  The indigenous soils must be tested for thermal resistivity and can only be used to fill the trench if it is found to have a thermal resistivity which meets the above requirement. If unsuitable imported material must be allowed for.  Parts of the route may have very high thermal resistivity, specifically where there is sphagnum moss. In such cases it should be assumed that the ground approximately three metres both side of the trench will have to be removed and replaced with suitable imported material. Sphagnum moss is also unlikely to be mechanically suitable for the supporting of cable trenches. Local regulations or landowners may have specific requirements for topsoil to be stripped and stored during the course of construction and replaced as part of the final reinstatement. There may be requirements as to the time of year when topsoil can be stripped and the methods of storage. Where minor roads are to be crossed, the thermal backfill should be extended upwards to the road reinstatement.

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7.5

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Preliminary scoping study: Cable installation direct in the ground Based on installation primarily in agricultural land a trench cross section typically as shown in Figure 75 is proposed.

Reinstatement as required to match original Ground surface Compacted excavated material (if thermally suitable) including replacement of topsoil to landowners requirements

Warning tape (as required)

Warning tiles placed on top of full area of backfill

Thermal Backfill Position of DTS fibres (if not included within cable construction) Power Cables Auxiliary ducts

c

b

a

a

b

c

Figure 75: Preliminary direct burial arrangement

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To achieve the required ampacity, the following dimensions have been calculated: Dimension mm a 450 b 175 c 100 d 1300 e 100 f 450 * g 1000 * Dimension “f” is based on a nominal cable diameter of 150mm Dimensions for Figure 75 For the purpose of initial cost estimates: Auxiliary ducts shall be 100 mm PVC conduit (Any optical fibre cable must be suitable for operation at 50 – 70°C when installed in close proximity to power cables) The trench may be of rectangular cross section as shown in which case shoring (usually timber) is generally required or may be battered (sloped) to avoid the need for support. An example of a trench with sloped sides is shown in Figure 76. With this type of arrangement it can be more difficult to keep the bottom of the trench clear of falling debris.

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Figure 76: Trench with sloped sides During cable installation cable rollers are required at close spacing. Pre-formed skid plates must be used at bends. The trench must be kept clean. The thermal backfill placed as a bedding under, over and around the cables shall be of the cement bound sand or fluidised thermal backfill type and shall have a dried out thermal resistivity no greater than 0.9 K.m/W[80,81]. Cement bound sand shall be installed dry and then compacted. It shall be free of sharp stones or flints which could damage the cables.  Where the route crosses agricultural land the top of the warning tiles placed above the thermal backfill must be no less than 900 mm below the surface. (this would require to be verified for Edmonton farming conditions).  The backfill placed above the cable forms part of the thermal design of the circuit; the warning tiles placed above thermal backfill must extend the whole length and width of the route. Trench filling above the thermal backfill and to either side of the trench must have suitable thermal characteristics. For this scoping study the limits are that the normal thermal resistivity should not exceed 0.9 K.m/W[80,81], and also that it should not exceed 3.0 K.m/W[82] when fully dried out. (The latter values would need to be verified by taking measurements and samples in situ in trial holes dug along the route when selected). :  The indigenous soils must be tested for thermal resistivity and can only be used to fill the trench they are found to have a thermal resistivity which meets the above requirement. If unsuitable, imported material must be allowed for.  Parts of the route may have very high thermal resistivity, specifically where there is sphagnum moss. In such cases it should be assumed that the ground approximately

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three metres both side of the trench will have to be removed and replaced with suitable imported material. The trench fill must be carefully compacted. Local regulations or landowners may have specific requirements for topsoil to be stripped and stored during the course of construction and replaced as part of the final reinstatement. There may be requirements as to the time of year when topsoil can be stripped and the methods of storage. Where minor roads are to be crossed, a ducted arrangement will be required. For the purposes of this installation study this may be considered identical to the duct block proposed for the duct-manhole system except that the ducts must generally be filled with bentonite for thermomechanical compatibility.

7.6

Minimum spacing between groups of cables of each circuit Each group of three single phase cables is installed in a separate trench as shown in Figure 77. This has been selected as:  Separate trenches give greater ampacity than multiple Groups of Cables within a single trench.  Separate trenches offer greater circuit security by having better survivability to third party damage  Separate trenches offer greater circuit security as adjacent Groups of Cables are less likely to be affected in the event of a repair. To achieve sufficient thermal independence the above trenches are spaced at no less than 7 metres between centres.

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Figure 77: Spacing between Groups of Cables Both two and three Groups of Cables are shown in Figure 77. Calculations for this scoping study indicate that to achieve the required ampacity, three cables per phase could be required if either (a) the cables are to be installed deeper or (b) the combined ampacity of two cables per phase is insufficient at one or more of the obstruction crossings.

7.7

Installation Swathe and spacing between circuits, In the selection of a preliminary installation configuration for the scoping study, the spacing between circuits considered the following benefits of physical separation:    

Greater circuit security by having better survivability against third party damage Reduce the induced voltage effects of one circuit on another, to facilitate the continued operation of one circuit whilst repairs are being conducted on the other. Greater circuit security as adjacent Groups of Cables are less likely to be damaged by excavation in the event of a repair. Minimise risk of damage to existing cables in a staged installation, when installing the Stage two Groups of Cables.

The spacing between Groups of Cables was initially selected as 7 metres, thus the spacing between circuits would be at least 7 metres to give the same amount of physical protection. This spacing between circuits was increased by a further 3 metres to 10 metres to allow for the construction of a temporary haulage road with room for passing places. This arrangement has been used previously for the construction of cable routes with two circuits comprising four

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separate trenches. A consequence of this is that 10 metres gives thermal independence between the circuits. In normal operation the circuits are required to carry 1,500 MVA simultaneously. For contingency operation each circuit alone is required to carry 3,000 MVA. The thermal independence between the circuits would prospectively increase the maximum simultaneous loading of both circuits to 3,000 MVA, although this has no benefit for this feasibility study. Typical installation Swathes (right of way) are shown in Figure 78 and Figure 79.

For the purposes of this scoping study, the following dimensions have been assumed: Dimension a b c e d

mm 1,500 5,500 10,000 10,000 3,000

f (total)

40,000

Figure 78: Arrangement of circuits and construction Swathe

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40 m wide swathe Positions of trenches

Haul road

Top soil storage

Figure 79: Photograph of construction swathe for four trenches Installers may have different proposals as to how to arrange their operation within the work area; the total width, however, is typical for this type of installation. 7.8

Sample ampacity calculation (XLPE cable) The results of a typical ampacity calculation for the scoping study, based on the methods contained in the IEC 60287 standard[83], are shown below:

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500 kV 2500 sq mm single-core XLPE cable Cu Milliken conductor Smooth Al sheath Pe serving Flat horizontal spaced, XB/SPB bonding Duct rating of two circuits (reversed sequence) Max DC resistance at 20°C 7.20 μΩ/m Conductor outside diameter 64.0 mm Conductor screen diameter 68.0 mm Insulation outside diameter 132.0 mm Insulation screen outside diameter 135.0 mm Core binder outside diameter 137.5 mm Sheath inside diameter 137.5 mm Sheath outside diameter 141.0 mm Serving outside diameter 152.0 mm Insulation TR 3.5 K.m/W Relative permittivity 2.5 Tan delta 0.001 Serving TR 3.5 K.m/W Frequency 60 Hz Depth to top of centre duct or pipe 1240 mm Duct liner inner/outer diameters 199.0 219.0 mm Duct liner TR 3.5 K.m/W Fill constants U, V, Y 1.87 0.312 0.0037 Duct block dimensions 700 1500 mm Duct block TR 0.9 K.m/W Depth to duct block centre 1450 mm Phase spacing (flat formation) 500.0 mm Circuit spacing (centre-to-centre) 7000 mm Ground thermal resistivity 0.900 K.m/W Additional sheath loss factor 0.0162 Ground temperature 20.0 °C Maximum conductor temperature 90.0 °C DC resistance at rating 9.181 μΩ/m Skin effect ks, ys 0.3500 0.1513 Proximity effect kp, yp 0.2000 0.0032 AC resistance at rating 10.599 μΩ/m Nominal capacitance 209.39 pF/m Dielectric loss per circuit 19.73 W/m Thermal resistance T1 0.4260 K.m/W Thermal resistance T3 0.0418 K.m/W Values for each phase when it is the reference cable: Leading Centre Lagging Lagging Centre Leading Loss factor 0.0681 0.2217 0.0681 0.0681 0.2217 0.0681 T4 total 0.8805 0.9767 0.8887 0.8887 0.9767 0.8805 K.m/W Adjusted T4 0.9169 0.9128 0.9254 0.9254 0.9128 0.9169 K.m/W Rating 1829.3 1732.1 1823.8 1823.8 1732.1 1829.3 A Sheath/non-magnetic layers resistance 45.33 μΩ/m Duct/pipe fill thermal resistance T4' 0.1946 K.m/W Duct liner thermal resistance T4'' 0.0533 K.m/W Duct block correction factor T4''' 0.0 K.m/W Sheath temperature 75.1 °C Cable surface temperature 73.2 °C Duct or pipe fill temperature 68.7 °C Conductor loss per circuit 95.40 W/m 'Sheath' loss per circuit 11.38 W/m Total losses per circuit 126.5 W/m Rated current (centre phase) 1732 A

Figure 80: Sample ampacity calculation

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The above ampacity calculation relates to XLPE cables installed in ducts, with two cables per phase, i.e. a total of six cables. The result is shown for the cable with the lowest ampacity. The above calculation gives a maximum ampacity of 1,732 amps; for a three phase group this is equivalent to 1,500 MVA at 500 kV. For six cables, i.e. two cables per phase, this is equivalent to a total carrying capacity of 3,000 MVA. The above calculation includes an allowance for the effect of mutual heating between two Groups of Cables. However, a centre to centre spacing of 7,000 mm between Groups of Cables has been selected for the scoping study. This gives nearly complete thermal independence and thus mutual heating is of very little significance and the ampacity with only one cable group carrying load will only be marginally greater than with both groups loaded. When installed as described for Stage 1, i.e. with one cable per phase, the transmission capacity can be taken as 1,500 MVA. No allowance is included for the effects of any mutual heating from the adjacent 500 kV circuit as 3,000 MVA is only required in a contingency situation for each circuit, i.e. the adjacent 500 kV circuit would not be carrying any load.

7.9

Stabilised backfill At the maximum cable operating temperature the ground surrounding buried cables exceeds 50°C at all practical depths. At this temperature moisture migration occurs with a consequent rise in the soil thermal resistivity, the thermal resistivity of most soils and backfill materials being highly dependant on the moisture content. To avoid a reduction in ampacity the following methods can be used:  The effect of the higher thermal resistivity of dried out soils is included in the ampacity calculation and the installation designed accordingly. Whilst this method is commonly applied to lower power cable systems, the high power transmission requirement of this project is such that little use can be made of this method of calculation.  The cables are surrounded with suitable material which has a stable value of thermal resistance over a long period of time even when subjected to constant heating. This is known as stabilised backfill. The stabilised backfill must fill an area equivalent to the 50°C isotherm surrounding the cables. The preliminary dimensions of the trenches shown in Figure 74 and Figure 75 include sufficient concrete or stabilised backfill to encompass the 50°C isotherm so that the value of thermal resistivity of 0.9 K.m/W can be taken for all the surrounding materials. Careful selection of concrete or backfill materials may allow a lower thermal resistivity to be used.

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7.10 Effect of obstructions on the route If the installation conditions at any point along the route are in any way less favourable than those upon which this calculation is based then the carrying capacity will be less than 3,000 MVA. These less favourable conditions typically include:  An increase in the depth at which the cables are laid.  An increase in the ground thermal resistivity.  A reduction in the spacing between cables.  An increase in the ground temperature as a result of other buried sources of heat. To avoid a reduction in the ampacity then the installation design must be modified at each location.

7.10.1 Methods of maintaining the ampacity where the cable depth must be increased. The most common type of obstruction which is likely to be encountered is where the cables must be installed at an increased depth to pass under an obstruction. For the purposes of this scoping study, the ampacity at increased depth the cables can be maintained either by installing the cables:  At increased phase spacing  In tunnels

7.10.2 Installation at increased phase spacing. To install the cables at increased phase spacing the cables can be installed either by:  Construction of a trench of increased width and depth  Trenchless methods, such as directional drilling For cables installed in the ground, the minimum phase spacing at which the ampacity can still be achieved at increased depth, whilst maintaining a centre to centre distance of 7 metres, is shown in Figure 81:

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500

1000

1500

2000

2500

0

500

Depth to top of cable (mm)

1000

1500

2000

2500

3000

3500

4000

Figure 81: Required phase spacing at increased laying depth The installation design at increased depth and increased phase spacing will require detailed thermal consideration for each location. As described in Section 7.9 above, the material within the 50°C isotherm surrounding the cable must be strictly controlled. Unless it can be proven that the thermal resistivity of surrounding indigenous soils will not exceed the design maximum, even when subjected to high temperatures for long periods of time, this requirement will mean: 

For cables installed in a trench: The width and depth may have to be significantly greater than that needed merely to accommodate, and provide protection for, the cables.



For cables installed using trenchless methods: The size of the drill and duct must be sufficient to accommodate the required stabilised backfill surrounding the cables, i.e. it must encompass the 50°C isotherm. This is shown diagrammatically in Figure 82. At a depth of 4 metres, the isotherm around each cable has a diameter of approximately 550 mm. For ducted sections of direct buried systems, it is normal to fill the duct with a thermally stabilised grout, bentonite being the normal choice. The requirement to completely fill the pipe and/or duct, without any risk of voids, restricts the maximum length of a trenchless system to that which can be completely grouted.

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Figure 82: Requirement for cable installed by trenchless method For a ground temperature of 20°C and a thermal resistivity of 0.9 K.m/W, and cables sufficiently widely spaced that they are each effectively thermally independent, the theoretical maximum depth at which they can achieve the required ampacity is 10 metres. For all twelve cables, this will require the width of the Swathe (right of way) to be increased from 40 metres to some 100 metres, this being impractical in most situations. The maximum depth at which cables can be installed without significantly exceeding the width of the Swathe of 40 metres is 4 metres. With this arrangement the segregation between cable groups will be reduced. A plan of a typical directionally drilled arrangement for twelve cables to pass under an obstruction is shown in Figure 83.

Figure 83: Typical directional drill arrangement, plan view

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Local increases in phase spacing increase the induced sheath voltage in the particular cable section. To eliminate sheath circulating currents, the difference between the induced sheath voltages in each of the minor sections of the cross bonding arrangement must not exceed the design tolerance. This can be accomplished by reducing the length of the section containing the wider phase spacing, or, less commonly, increasing of the phase spacing in other sections. The requirement to balance the cross bonding arrangement also restricts the maximum length of a trenchless installation.

7.10.3 Installation in tunnels. For cables which cannot be installed in either a conventional trench or using a trenchless method as described above, an alternative local construction will be required. For the purposes of the feasibility study this will consist of two short ventilated tunnels, one tunnel being used for each circuit. These tunnels will require thermal analysis to establish if natural ventilation will be sufficient, or if forced ventilation will be required. The tunnels will also have to be designed to withstand any thermomechanical forces which may be transferred to the structure of the tunnels from the cables. The tunnel and shafts must be designed to allow the cables to be installed without infringing the minimum bending radius. This will be advised by the manufacturer but for XLPE cable the minimum permissible bending radius would typically be some thirty times the overall diameter of the cable, or four to five metres fore a 500 kV, 2,500 mm², cable. A typical tunnel arrangement is shown in Figure 84.

Headhouse Ground surface Cables in trench

Obstruction

Shaft

Cables in Tunnel

Figure 84: Typical naturally ventilated tunnel A typical headhouse arrangement for a naturally ventilated tunnel is shown in Figure 85. The headhouse arrangement for a tunnel with forced ventilation would be considerably larger, requiring space for fans, control equipment and noise suppression.

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Figure 85: Compound containing two headhouses for naturally ventilated tunnels

7.10.4 Further methods of obstruction crossing. If the ampacity cannot be maintained by either increased phase spacing and the construction of a tunnel is not viable, then further developments may be possible. These have not been included in this Scoping Study. Such developments could include the use of:  A cable bridge, whereby a structure is built to carry the cables over, rather than under the obstruction. This would generally expose the cables a greater risk of third part damage, and would also increase the temperature range to which they would be exposed.  A forced cooling system. This would require significant maintenance commitments to ensure reliability  The development of a different design of cable for particularly severe obstruction crossings. This would require additional product development and testing, including the development of transition joints for where the cable is spliced to the normal cable  The use of an additional cable per phase, i.e. an additional Group of Cables per circuit. As no joint arrangement exists for splicing three cables together, the additional Groups of Cables would have to be installed throughout the entire cable route.

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7.11 Cable lengths between joint bays To limit the induced voltage to less than 250 V and to provide a manageable length which can be delivered and installed a maximum reel length of 700 metres has been selected for this scoping study. . 7.11.1 Outline reel dimensions Calculations show that this length of cable can be transported on a reel with an overall diameter of 4.3 metres and an overall width of 4.3 metres. The weight of cable would be some 28 Tonnes; if the reel is assumed to have a weight of 5 to 7 Tonnes then the gross weight is 35 Tonnes. This is shown in Figure 86.

Dimension Overall reel width Overall reel diameter Gross weight

mm 4,300 4,300 35,000kg

Figure 86: Typical reel dimensions and weight This weight relates to the design of cable used for the Scoping Study which has an Aluminium sheath. Other cable designs which incorporate a lead sheath would be heavier.

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Figure 87: Conventional delivery Delivery of cables from the factory to site almost invariably involves road transportation. The conventional method of loading a cable reel onto a lowboy (low loader) is shown in Figure 87. This arrangement, however, is only suitable for overall reel widths which are not significantly greater than the width of the vehicle. However, for the size and weight of the cable and reel selected for the preliminary design study, it the reels would probably be delivered in an arrangement similar to that shown in Figure 88. This may size of load may require special permission from local authorities, police escorts, or removal of street furniture2 on some parts of the route from the manufacturer.

Figure 88: Longitudinal reel on lowboy

2

Street furniture is objects and pieces of equipment installed on roads, including traffic barriers, streetlights, traffic lights, traffic signs, bus stops and waste bins. Larger structures such as pedestrial bridges may also be removed.

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7.11.2 Cable reel transportation study Based on the dimensions and weights of the reel calculated in the previous section the Heartland Project Team performed a study of a) the available road and rail routes from possible ports of entry to Edmonton and b) the transportation costs. The study is recorded in Appendix, Section 12. The HPT study showed that transportation of reels carrying 700 m cable lengths from both east and west coast ports is feasible.

7.12 Manholes and joint bays Jointing vaults or joint bays would be constructed at the positions between each individual cable reel length. For the 2,500 mm² conductor envisaged for the 500 kV Study Project underground cable, initial calculations indicate that the jointing vaults should have an internal length of 14.25 metres, and an internal width of 2.20 metres. Ideally jointing vaults would be prefabricated and delivered by road transport but could also be fabricated in situ. Typical joint bay dimensions are depicted in Figure 89, Figure 90 and Figure 91.

Figure 89: Plan of typical joint bay

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Figure 90: Longitudinal elevation of typical joint bay

Figure 91: Elevation cross section across typical joint bay The joint bays would be fully filled with thermal backfill before putting into service. Drawing of joint bays upon which cost estimates have been based are included in Appendix, Section 26.

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7.13 Tunnels As an alternative to the surface route 500 kV XLPE cables may be installed within a tunnel. The two tunnel designs envisaged are as follows and as depicted in Table 35 below:

Depth to top of tunnel

Internal dimensions

Cut and Cover Round (deep bored) 1.5 metres minimum 40 metres (typical) (depth may have to increase locally to cross obstructions and undulating land) 2 tunnels, each 3 metres x 3 metres 2 tunnels each 3 metres diameter Table 35 Tunnel dimensions for scoping study

Shafts of approximately 15 metres diameter are required at 5 km intervals:  The shafts would not have permanent powered elevators.  A segregated staircase will be installed in each shaft.  Air inlet temperatures for tunnel civil engineering design:  Maximum 50°C  Minimum -20°C  The ventilation system would allow personnel to safely enter the tunnel.

7.13.1 Tunnel ampacity Enough heat cannot dissipate from long tunnels to prevent eventual overheating of the cables. Forced ventilation is therefore required. The cable ampacity within a tunnel has been assessed based on a summer air inlet temperature of 17.5°C monthly average and minimum winter air inlet temperature of 11.7°C. However, to ventilate tunnels with very cold ambient air would cause the temperature of the joints to fall below their anticipated minimum design temperature. To restrict the minimum cable and joint temperature to no less than 0°C, studies have been conducted to simulate the effect of restricting the airflow rate during winter. (If this is inadequate it may be necessary to heat the inlet air to 0°C.) The calculated air and cable temperatures at both the inlet and outlet ends of the tunnel are shown in Figure 92. This simulation was performed to demonstrate that both the maximum and minimum cable and joint temperatures can be limited by carefully designed control of the air flow rate. Figure 92 shows temperature variations over a 10 year period. Extending the period has little effect on the final temperatures.

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Figure 92:Tunnel temperatures over a 10 year period The tunnels shall provided be with a ventilation system capable of supplying an air flow rate of 5 metres per second. Intermediate shafts will need to be segregated vertically to separate the air flow system between adjacent tunnel sections and for fire separation. Noise silencer buildings will be required around all fans.

7.13.2 Cable installation in tunnels Cable installation into tunnels is highly specialised. For all tunnel applications, cable installation systems are specially designed. On occasion this has included the design and procurement of specialised cable handling vehicles for the tunnel to reduce the potentially hazardous cable handling. The following method is based on the method which is being developed for 400 kV cable tunnels 

The cable drums will be mounted above ground on powered stands with a braking system. The cables will be lowered vertically down the shaft through a temporary guide system and then around a preformed bend at the base of the shaft. In the tunnel design shown we have allowed for an I-beam transportation system in which the cable is supported on hangers and nose pulled by a specially designed vehicle.

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The cable will be supported on steel supports within the shaft such that it is vertically waved and held rigid at nodes by high strength clamps, this being a semi-flexible system. The cable in the tunnel will be set into a vertically sagged system with saddle cleats affixed to supporting steelwork at 7 metre intervals. The sag is designed to accommodate the expansion and contraction of the cable, such that longitudinal forces do not occur.

Figure 93: Typical tunnel cable clamp (cleat) for a sagged system A typical ‘saddle’ cable clamp is shown in Figure 93; it is curved lengthwise to allow the cable to expand and contract. The three phase cables will be restrained at mid span by a short circuit strap arrangement comprising of three simple single phase clamps joined by two vertical straps.

7.13.3 Tunnel cross sections Two types of cable tunnel are available, a deep bored, tunnel, of circular cross section (Figure 94), and a shallow, rectangular section tunnel that can be constructed by ‘cut and cover’ type methods (Figure 95).

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Figure 94:Tunnel cross section: deep tunnel

Figure 95:Tunnel cross section: cut and cover

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7.14 Staging of the cable installation Cross sections have been prepared to show how the installation could be staged if all cables were not to be installed initially. This is represented by Scenario 2 and shown diagrammatically in Figure 96. Scenario 4 is also a staged installation, but has not been described in such detail.

Figure 96 Scenario 2, one group per circuit installed initially (black), the second later In Figure 96 the block dotted lines represent underground cable which would be installed in Stage 1, and the red dotted lines represent underground cable which would be installed in Stage 1 The objective of this section of the document is to give a) The installation layout for the costing of the ‘staging’ option and b) The reasons for the proposed layouts. Stage 1 is circuit A and circuit B each having a maximum capability of 1,500 MVA Stage 2 is circuit A and circuit B each having a maximum capability of 3,000 MVA The installation cross sections are shown and described for stage 1 (1,500 MVA) and Stage 2 (3,000 MVA) for direct buried, duct-manhole, deep tunnel and cut and cover tunnel installation options. The reasons for the proposals are given. For un-staged installation in tunnels, permanent lighting equipment is not necessarily recommended, with the consideration of reducing the maintenance requirement. For the staged work, however, permanent lighting should be installed to assist the timely installation of the Stage 2 cable and joints. The advantages of staging are:  That investment can be staged, allowing expenditure to be deferred (The financial effects of staging are analysed in Appendix, Section 3).

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 

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The cable installation time is halved and will help achieve the objective of installing all of the cable in one summer season in which the air temperature is above the minimum of 0°C required for a PE jacket A wider range of service proven, designs of straight splice will be available for selection for the final circuit upgrading in say, 20 years time. Full advantages of improvements in the cable design cannot necessarily be taken, for the reasons given below.

For arrangements with two Groups of Cables per circuit, i.e. Scenarios 1A.10 and 1B.20, it may be possible to arrange the electrical connections at the Transition Stations in such a way that one of the two Groups of Cables that comprise the cable Circuit could remain in-service whilst the other Group of Cables is taken out of service for maintenance or repair. This advantage is lost in the case of Stage one of Scenarios, 2A.10 and 2B.20, where each circuit would consist of one Group of Cables only. In this case each circuit would not be capable of transmitting any power whilst it’s only Group of Cables was out of service. This would give the transmission system operator less flexibility in how he would be able to operate the system. In the event that both Groups of Cables had to be taken out of service for repair concurrently then no power could be transmitted. The key parameters of staged installation are summarised below: Installation type

Phase spacing

Duct-manhole system

Number of cables per phase

500 mm

Stage 1 (1,500 MVA)

One

Stage 2 (3,000 MVA)

Two

Direct buried

450 mm

Stage 1 (1,500 MVA)

One

Stage 2 (3,000 MVA)

Two

Cables in tunnels

500 mm

Stage 1 (1,500 MVA)

One

Stage 2 (3,000 MVA)

Two

Figure 97: Staging summary

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7.15 Staged duct manhole cable installation Cross sections of staged installation for a duct-manhole system are shown in Figure 98

Figure 98: Scenario 2, staging for the duct-manhole system

7.15.1 Installation layout Stage 1: 1,500 MVA total per circuit   



All four duct banks (Circuit A, Groups 1, and 2 and Circuit B, Groups 1, and 2) and manholes are installed together. The cables are installed in the Circuit A, Group 1 and Circuit B, Group 1, ducts and the splices are assembled The ducts in Circuit A, Group 2, and Circuit B, Group 2, are proven by pulling through a mandrel, are sealed and a low positive gas pressure applied (equivalent to 5 psi at -10°C). Maintenance checks will be required to ensure that the ducts and manholes remain in sound condition. The haul road in the centre (if used) has to be removed to allow the land to be returned to its former use.

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Stage 2: 3,000 MVA total per circuit    

The haul road is rebuilt to allow delivery of reels and accessories etc. to each manhole. If possible the haul road may be reduced in width to single track to take advantage of reduced construction traffic. The Circuit A, Group 2, and Circuit B, Group 2, ducts are unsealed, are visually inspected by CCTV camera, are proven by mandrel and are cleaned. The Circuit A, Group 2, and Circuit B, Group 2, cables are installed. The new cables are required to have a) closely similar dimensions to the original cables to achieve the same impedances and to ensure that the load is shared 50/50, b) closely similar diameters to ensure the same thermomechanical performance. Full advantage cannot necessarily be taken of possible improvements to cable technology at the date at which the circuit is required to be upgraded.

7.15.2 Reasons for proposal   

The two circuits, A and B, are widely spaced by the width of the haul road (approximately 10 meters) to minimise the risk of third party damage to both circuits and common mode failure. The layout permits Circuit A and Circuit B to diverge and take different routes at certain positions Installation of all the ductbanks at Stage 1  Reduces the risk of damage during installation of the existing Circuit A Group1 and Circuit B Group 1 cables  Reduces the investment cost of Stage 2  Achieves economies of scale in reducing the unit costs of installing all the duct banks together.  Reduces the installation time of Stage 2

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7.16 Staged cable installation direct in the ground Cross sections of staged installation for a direct burial system are shown in Figure 99.

Figure 99:Scenario 2, staging for cables direct buried in the ground

7.16.1 Installation layout   

Stage 1: 1,500 MVA total per circuit The two trenches closest together (Circuit A Group 1 and Circuit B Group 1) are installed first Space is reserved to excavate the two adjacent trenches later. The haul road in the centre (if used) has to be removed to allow the land to be returned to its former use. Stage 2: 3,000 MVA total per circuit

  

The haul road is rebuilt in the centre of the reservation. The two outer trenches (Circuit A, Group 2, and Circuit B, Group 2) are cut and the cables are installed. Care is taken not to drive heavy plant over the original trenches.

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

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The new cables are required to have closely similar dimensions to the original cables and spacing to achieve the same impedances and to ensure that the load is shared 50/50. Full advantage cannot necessarily be taken of possible improvements to cable technology at the date at which the circuit is required to be upgraded.

7.16.2 Reasons for proposal   

The two circuits, A and B, are widely spaced by the width of the haul road (approximately 10 meters) to minimise the risk of third party damage to both circuits and common mode failure. The layout permits Circuit A and Circuit B to diverge and take different routes at certain positions This arrangement has been satisfactorily used in the UK to increase the capacity of a buried cable circuit.

7.17 Staged cable installation in deep tunnel Cross sections of staged installation for a deep tunnel system are shown in Figure 100.

Figure 100: Scenario 2, staging for cables installed in deep tunnels

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7.17.1 Installation layout Stage 1: 1,500 MVA total per circuit   

The two tunnels are constructed together with the supporting metalwork for all four groups of cables. The full air cooling equipment is designed and installed for each tunnel. Note, if required approximately half of the cooling equipment may be omitted and installed at the time of the installation of the Stage 2 cables. One circuit is installed in each tunnel (Circuit A Group 1 and Circuit B Group 1) Stage 2: 3,000 MVA total per circuit

 

 

Circuit A, Group 2, and Circuit B, Group 2, cables are installed; noting that an outage will be required on Circuit A and Circuit B in turn to permit cable installation and jointing to be performed. The new cables are required to have closely similar dimensions to the original cables and spacing to achieve the same impedances and to ensure that the load is shared 50/50. Full advantage cannot necessarily be taken of possible improvements to cable technology at the date at which the circuit is required to be upgraded. The installation method and associated tunnel furniture (for example the I beam transport system) will require to be maintained and reused. The performance and condition of the ventilation system shall be reviewed and up-rated as necessary.

7.17.2 Reasons for proposal  

The two circuits, A and B, are installed in separate tunnels to minimise the risk of common mode failure. The layout permits Circuit A tunnel and Circuit B tunnel to diverge and take different routes.

7.18 Staged cable installation in cut and cover tunnel Cross sections of staged installation for a deep tunnel system are shown in Figure 101.

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Stage 1 1500MVA per circuit Ground surface Circuit A Group 2 (Steelwork installed)

Circuit A Group 1

Circuit B Group 1

Circuit B Group 2 (Steelwork installed)

Stage 2 3000MVA per circuit Ground surface Circuit A Group 2

Circuit A Group 1

Circuit B Group 1

Circuit B Group 2

Figure 101: Scenario 2, staging for cables installed in cut and cover tunnels

7.18.1 Installation layout Stage 1: 1,500 MVA   

The two tunnels are constructed together with the supporting metalwork for all four groups of cables. The full air cooling equipment is designed and installed for each tunnel. Note, if required approximately half of the cooling equipment may be omitted and installed at the time of the installation of the Stage 2 cables. One circuit is installed in each tunnel (Circuit A Group 1 and Circuit B Group 1)

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Stage 2: 3,000 MVA  

 

Circuit A, Group 2, and Circuit B, Group 2, cables are installed, note an outage will be required on Circuit A and Circuit B in turn to permit cable installation and jointing to be performed. The new cables are required to have closely similar dimensions to the original cables and spacing to achieve the same impedances and to ensure that the load is shared 50/50. Full advantage cannot necessarily be taken of possible improvements to cable technology at the date at which the circuit is required to be upgraded. The installation method and associated tunnel furniture (for example the I beam transport system) will require to be maintained and reused. The performance and condition of the ventilation system shall be reviewed and up-rated as necessary.

7.18.2 Reasons  

The two circuits, A and B, are installed in separate tunnels to minimise the risk of common mode failure. The layout permits Circuit A tunnel and Circuit B tunnel to diverge and take different routes.

7.19 Alternative staging arrangements Scenario 3 (un-staged) and scenario 4 (staged) utilise three groups of cables rather than four. These are described in Section 2.2. For the staged installation of Scenario 4:  The installation of the cable for stage 1 of Scenario 4 would be similar to the installation of the cable for stage 1 of Scenario 2. The GIS substation would be constructed during stage 1.  The installation of stage 2 of Scenario 4 would be similar to the installation of stage 1 of Scenario 2 with the exception that only one additional Group of Cables would be installed. The above Scenarios 1, 2, 3 and 4 are all based on the presumption that each Group of Cables can transmit 1,500 MW and hence no more than two cables per phase (i.e. two Groups of Cables) will be required to transmit 3,000 MVA. If three Groups of Cables (i.e. three cables per phase) per circuit are required for the transmission of 3,000 MW, the cable layouts, including staged scenarios, would require further consideration. Situations where three Groups of Cables per circuit may be required are:  If the cables and joints have to be buried deeper to provide protection against low winter temperatures, with a consequent reduction in ampacity.  At one or more of the obstruction crossings, if the maximum ampacity of each Group of Cables becomes less than 1,500 MW.

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7.20 Alternative SCFF cable type for scoping study For this scoping study two types of 500 kV SCFF (Self Contained Fluid Filled) cables have been considered, LPP (Laminated Polypropylene Paper) insulated and paper insulated. SCFF cables are included in the feasibility study because the associated splices have proven low temperature performance. LPP is the most likely type of insulation to be offered for a SCFF solution as it is an efficient, low loss material. Cables with paper insulation have not been considered in detail for this design study as they have higher losses and hence lower ampacity than LPP insulated cables. The thickness of the dielectric of fluid filled cables is generally designed based on the maximum permissible stress at the conductor screen at the maximum impulse voltage. For the feasibility study a maximum permissible (impulse) stress of 82 MV/m at 1,550 kVp has been used for both LPP and paper types. This results in a maximum stress at the conductor screen of 16 MV/m at a working voltage of 525 kV. This results in a thinner insulation and smaller cable than the generic XLPE design. Fluid filled cables are generally constructed with either a corrugated seamless aluminium sheath or a reinforced lead sheath. For the feasibility study the cable design has a corrugated seamless aluminium sheath. This type of design has been favoured by many users at it gives better resistance to third party damage and vibration and hence has better hydraulic integrity. The selected SCFF cable constructional details and dimensions are shown diagrammatically in Figure 114. No civil installation cost estimates have been prepared by the HPT specifically for SCFF cable. The installation design could be expected to be fairly similar for both SCFF cable systems and XLPE cable systems, but provision must be made for the additional hydraulic equipment (fluid tanks and pressure monitoring equipment) required for an SCFF system.

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Alternative SCFF 500 kV Cable For Scoping Study 3,000mm² Milliken stranded copper conductor, LPP or paper insulation, single-core, Corrugated aluminium sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

Diagrammatic only Item 1 2 3 4 5 6 7 8

Details Central fluid duct Copper conductor Conductor binder and screen LPP or paper insulation 25.5mm min Insulation screen and binder Radial clearance Corrugated Aluminium Sheath Polyethylene Jacket with semi-conductive coating

Approximate weight 46 kg/m Figure 102: Alternative SCFF 500 kV cable

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Nominal diameter (mm) 16.4/18 72.5 73.8 124.4 125.6 142.2 150.2




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7.20.1 SCFF cable power losses Coated conductors have not been developed commercially for SCFF cables. The AC conductor resistance thus tends to be higher than the equivalent sized XLPE cable conductor with coated wires. The conductor losses are thus higher in a SCFF cable than for an XLPE cable. When energized, dielectric losses occur within the insulation of cables. These occur whenever the cables are energized, even if no useful load is being transmitted. The dielectric losses are a function of:  working voltage and frequency  dimensions of the insulation  relative permittivity (ε) of the insulation  Dissipation factor (tan δ) of the insulation At a working voltage of 500 kV and a frequency of 60 Hz the dielectric losses form a substantial proportion of the total power losses from the cable. As described above, the higher design stresses that can be used for SCFF cables allow a reduced thickness of insulation to be used compared with that of an XLPE insulated cable. The relative permittivity and loss factor are both higher for LPP than for XLPE, and the values for paper insulation are higher still. (Values for relative permittivity, ε, and loss factor are given in IEC 60287-1-1[83] for XLPE, LPP and paper.) This results in the dielectric losses of LPP or paper insulated cables being significantly higher than those of XLPE cables. For the cables in this scoping study the dielectric losses per metre of core are as follows:  XLPE: 6.6 W/m  LPP 13.1 W/m  Paper 28.1 W/m These would be some 11% higher at 525 kV. The relatively high losses of the paper insulated type make it an unattractive option and thus it has not been considered in detail. Both the generic XLPE cable and the SCFF have aluminium sheaths and the losses in the sheath are similar.

7.20.2 SCFF LPP cable installation configuration

7.20.2.1 SCFF cables in Duct Manhole system For installation in a duct manhole system with three cables per phase (three Groups of Cables) would be required. Whilst SCFF LPP cables could achieve the required 3,000 MVA capacity with two

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3,000 mm² cables per phase at a phase spacing of approximately 1 metre, this phase spacing is too wide to be used practically for long routes as:  To cross obstructions the cable depth must be increased. With two cables per phase the maximum depth at which the required ampacity can be maintained would not be sufficient to cross some obstructions. (Ampacity can normally be maintained at increased depths by local increase of the phase spacing; if the phase spacing is already very wide then further increases offer little increase in ampacity)  The induced sheath voltage is greater at wider phase spacing. The voltage induced on the sheath at a phase spacing of 1 metre will be significantly greater than at the 450 mm to 550 mm considered for other arrangements. In consequence the maximum length of section that can be used without exceeding the maximum permissible sheath voltage will be lower at wider phase spacing and an increased number of splices will be required.  It is often difficult to find a route sufficiently wide to accommodate this spacing for the entire length of the route. A system using two SCFF LPP cables in ducts has therefore not been considered further at this stage, but if XLPE cables prove unsuitable then the feasibility of using SCFF cables with a conductor size larger than 3,000 mm² could be considered. A system with three Groups of Cables installed in ducts has not been considered in detail as this is likely to be a very expensive system. If it is to be considered further then the following could be considered:  Reduced conductor size and/or reduced phase spacing  Installation of the cables in three stages rather than two, with the first stage consisting of one Group of Cables only per circuit, but having an ampacity of less than 1,500 MVA per circuit. A cable system design using paper insulation instead of LPP may be possible but is unlikely to offer any advantages because of its higher dielectric loss.

7.20.2.2 SCFF cables in Direct Burial system To counteract the effect of the additional cable losses described above the conductor size of the SCFF LPP cables has been increased to 3,000 mm² for this scoping study. This permits the 3,000 MVA to be carried with two cables per phase for direct buried systems, albeit at an increased phase spacing of 550 mm. This would require a redesign of the cable trench.

7.20.2.3 SCFF cables in long tunnels SCFF cables have not been considered for installation in long tunnels because of the damage that could occur in the event of a fire.

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7.21 Cable system routine maintenance The following recommendations for maintenance are required in order to estimate the cost of operating the cable system.

7.21.1 Maintenance for 500 kV XLPE cable systems The following represents an example of good practice. Rigorous maintenance schedules represent an onerous requirement for the transmission system operator who may be prepared to accept the additional risk of a reduced frequency of some of the maintenance. The maintenance costs which have been prepared for the 500kV Study Project are based on the maintenance information given in Appendix, Section 25.

7.21.1.1 Cable route The cable route should be visually inspected to confirm:  No unauthorised excavations have occurred in the vicinity of the cables  All route markers are present and in good condition Any discrepancies should be made good. Inspection frequency: weekly

7.21.1.2 Sheath bonding system It is necessary to prove the integrity of the oversheath (jacket) periodically by applying a test voltage between the sheath and ground. The normal maintenance test voltage is 5 kV DC for a duration of one minute. Even whilst out of service cable sheaths can be subject to high induced voltages under through fault conditions on adjacent circuits, so before testing it is necessary to establish whether "induced voltage conditions" apply to the cable in question. The test voltage should be applied to each individual sheath section in turn with adjacent sections grounded. A test is made in each direction from each alternate link box position. This ensures that the full test voltage is applied across any sheath sectionalising barriers, thus proving their integrity.

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During the course of the test links in link boxes are removed or rearranged so as to sectionalise the sheath and temporarily ground sections adjacent to the one under test. Most modern designs of SVL should not have to be disconnected for these tests but this must be checked before commencing testing. The 5 kV DC source should be designed to limit the current in the event of a breakdown. A small portable generator may be needed to power the test set. Any excessive leakage current will required to be investigated and repairs conducted as necessary. At the same time the SVLs should be checked and the electrical resistance characteristic measured; the SVLs and leads should be visually inspected for signs of degradation, e.g. corrosion, moisture ingress, etc. Frequency of routine tests on sheath bonding equipment: 

The oversheath (jacket) and SVL tests should be repeated annually



If an internal or through fault occurs on a cable circuit then the oversheath (jacket) and SVL tests shall be conducted. In addition the cable sheath to ground metallic path should be checked.



It is also prudent to check the integrity of the oversheath (jacket) prior to the commencement of any major works which are to be conducted in the vicinity of the cable circuit.



Whenever links are removed and replaced then the contact resistances must be checked.

7.21.1.3 Manholes, Link boxes and Link pillars Manholes, link pits, road covers, link boxes and above ground pillars should be maintained in good condition. The internal rim of the cover frame of any pits housing link boxes or manholes should be regularly cleaned and greased. The condition of any anti-corrosion paint should be checked and renewed as required. The condition and legibility of warning messages and labelling should be checked and renewed as necessary. Any manholes found to be flooded should be drained and measures taken avoid recurrence.

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Where manholes include cable splices, any cable clamps installed to support or restrain the cables should be inspected for mechanical integrity and to ensure that expansion forces from the cables have not compromised their installation. The condition of any cable splices in the manholes shall be inspected to ensure that cable expansion is not changing the geometry of the splice or moving the splice. Inspection frequency: annual.

7.21.1.4 Sealing Ends (Terminations) Terminations should be visually inspected for signs of degradation, noting in particular the condition of:  main insulators  support insulators  cable sheath closures  corona shields Comparative infra red/thermal imaging inspections of the terminations should be conducted. Inspection frequency: annual The terminations should be visually inspected for signs of oil leakage. If the Sealing Ends are of the pressurised type, with electric contact pressure gauges or transducers, then the insulation resistance of connecting leads and the correct operation of pressure switches should be checked. If the terminations include any facility to allow the oil condition to be sampled and/or checked then this should be conducted in accordance with the supplier’s recommendations. Inspection frequency: annual To avoid the possibility of unacceptably high cantilever forces being applied to the top connectors of air insulated Sealing Ends, busbar connections should be checked to ensure that any sliding connections are free and that drain holes are not blocked.

7.21.1.5 Condition monitoring systems The correct operation of the DTS system should be checked in accordance with the supplier’s recommendations.

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After several years operation at high temperature DTS fibres may deteriorate. Depending upon how these are installed it may be possible to blow in replacement fibres. If fitted, the correct operation of any “in-service” PD detection systems should be checked in accordance with the supplier’s recommendations. If fitted, the correct operation of any SVL monitoring systems should be checked in accordance with the supplier’s recommendations. If conducted as part of the commissioning tests, the cable systems have been ‘fingerprinted’ by TDR measurements, then repeat TDR measurements should be made if and when possible.

7.21.1.6 Recommended routine maintenance on 500 kV XLPE cable systems in tunnels The maintenance regime for cables in installed in tunnels is generally less than that for cables buried in the ground. Tunnel systems are commonly designed so that personnel do not regularly have to enter the tunnel to conduct inspections. Routine inspection of cable supporting structures and cleats should be performed annually but may be conducted by remotely operated equipment. The cable should be inspected at the same time. Routine electrical tests on the integrity of the cable oversheath (jacket) are not required. Routine inspections of link box pits and manholes are not applicable. The condition of the tunnel should be checked in accordance with the structural engineer’s recommendations. The correct operation of the tunnel system should be checked in accordance with the supplier’s recommendations. These systems could include ventilation, water drainage pumping, emergency lighting, fire detection and suppression, communication, auxiliary power supplies.

7.21.2 Recommended routine maintenance on 500 kV SCFF cable systems Significant additional maintenance is required for SCFF systems. Suitably trained personnel and specialist equipment would be required for the maintenance of an SCFF cable system. SCFF cables are not recommended for the 500 kV Study Project and a description of the additional maintenance requirements has thus not been included in this report.

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7.22 500 kV cable system spares and repairs. Normally spares would be expected to be held in stock. As a minimum these would include one reel of each type of cable, two joints and one termination for each design of cable. These would be packed for ‘long term storage’ but would exclude components with limited shelf life. As a minimum, the lengths of spare cable must be long enough to be installed in the longest span used on the system. If the installation design uses prefabricated joint bays to house joints (splices) then spare joint bays should also be held as part of the emergency spares. To ensure tooling availability and to save time in the event of a repair, a set of any specialist tooling should also be held in store. In the event of a fault the items in stock would have to be inspected for completeness and degradation. Any missing or unusable items, plus the items with limited shelf life, would then have to be procured urgently from the manufacturer, and despatched to site by airfreight. Some suppliers may suggest it prudent that, after a certain length of time in storage, one piece joint mouldings or stress cones should be returned to the factory for re-inspection and test. Replacement spares, again packed for long term storage would then be ordered to replace those taken from the users stores. Most EHV cable system faults which involve a failure of the primary insulation (i.e. not just damage to the cable jacket) cannot be repaired by a single joint or termination. For direct buried systems, a repair to the primary insulation would require the insertion of a short length of cable and either two joints or one joint and one termination. If the fault is at or near a termination then one joint and one termination would be used, otherwise two joints would be used. The length of cable would normally be less than 20 metres but depends upon the extent of the damage and the availability of a suitable position to install a new joint bay. For example, in the case of a ‘digin’ at a road crossing, it may be impossible to build a repair joint bay at the position of the fault, separate joint bays would therefore be required for repair joints on either side of the fault position. These may be on opposite sides of the road. The replacement cable would be cut from the reel held in store. New pulling eyes or despatch caps would have to be fitted to the cut cable ends. A new joint bay (or two bays if sufficient room cannot be found for a repair bay at the site of the fault) would be designed and constructed; these would have to be thermally and thermo-mechanically checked to ensure that the cable and joints would not be subjected to undue temperatures or mechanical forces. For duct manhole systems, if it can be confirmed that the duct has not been damaged or can be completely repaired, then it may be preferable to replace the whole span length. In this case two joints and one span length of cable would be required. The replacement joints may have to be displaced slightly if it cannot be guaranteed that the existing joints can be removed without damaging the cable. In such cases, the design of jointing vault would have to be revised. The thermo-mechanical design of the revised jointing vault would have to be checked. If the whole span is not to be replaced, then a short replacement length would be inserted, in a similar arrangement as described for a direct buried system. For a duct manhole system, where complete span lengths may be replaced, it may be prudent to hold more spare cable than would be required for direct buried systems.

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For 500 kV cables systems installed in tunnels, the tunnel should be designed initially to ensure that repair joint positions can be constructed at any appropriate positions within the tunnel. Again the normal arrangement would be a short length of cable and two joints, or one joint and one termination. Cables in tunnels are virtually immune from third party damage so a failure in a tunnel is therefore more likely to involve a joint. In the event of a joint being replaced, it will be necessary to ensure that the sheath bonding cable lengths are not excessive. These are normally limited to a maximum of 10 metres, but detailed calculations would be necessary to establish the maximum permissible length in each case. In an extreme case so much cable could have been damaged that it is not possible to locate either of the repair joints close enough to the original joint position that the bonding cable limit is not exceeded. In such cases three repair joints may be required, one joint with sheath sectionalising insulation at the same position as the original joint, and two joints without sheath sectionalising insulation, positioned either side of the original joint position. This situation could occur in the event of a fire in either a tunnel or a jointing vault. In such cases it is also possible that the adjacent phases could have suffered damage, and up to nine repair joints would be required. In the event of a cable system fault, tests should be done prior to re-commissioning of the circuit. Ideally these tests would include an HV AC test similar to the commissioning test, but at a reduced voltage depending upon the age of the circuit, accompanied by PD monitoring of accessories. This would be particularly important in the case of a repair following an electrical failure of a joint, when it would be advisable to check the condition of all other joints as well as the newly installed repair joints. It may not be possible to obtain suitable AC test equipment before the time that the user wishes to reenergize the cables. In such cases it may be appropriate to conduct a ‘soak’ test, whereby the cables are connected to the system for test purposes only. Prior to re-commissioning the sheath voltage limiters in the link boxes should also be checked. It would therefore be prudent to keep a supply of SVLs in storage; so that they are available should replacements be necessary. The cost of spares which have been prepared for the 500kV Study Project are based on the maintenance information given in Appendix, Section 25.

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ELECTROMAGNETIC FIELD PROFILE

The electromagnetic field (EMF) is comprised of two components, a magnetic field which is produced by the flow of current in the conductor, and an electrostatic field produced by the voltage at the conductor. Both components exist in the proximity of an overhead line. In an underground cable, (a) the electrostatic field is completely contained within the cable by the insulation screen and does not exist outside the cable and (b) the magnetic field exists in the proximity of the cable. The magnetic field profile, transverse to the route, has been calculated by HPT and is given in Appendix, Section 13. Magnetic field magnitude is expressed in North America, in units of magnetic flux density, milligauss (mG). This has been calculated for both underground cable and overhead lines at 1 metre above ground carrying the same power. For convenience some of the values from Section 2, Summary of Findings, of the HPT report are copied below in Table 36. The majority of potential suppliers proposed cables laid in flat, horizontally spaced, formation at a depth of 1.3 metres. Horizontal spacing is the most efficient and economical solution for a direct buried system. Whilst cables can be installed in other formations such as open trefoil, these formations have disadvantages of thermal inefficiency in dissipating heat, complexity of installation to lay cables at different levels and difficulty of access for repair. Magnetic field flux densities calculated for the laid flat spaced arrangement, with four trenches (Scenarios 1A.10 and 1B.20), are shown in Table 36 to be 81 mG when both circuits carry 500 MW. The equivalent magnetic field at 1,500 MW per circuit would be 243 mG. The equivalent magnetic field for contingency operation in which one circuit carries 3,000 MW would be approximately 486 mG. Each of these levels is below the exposure guidelines established by the International Commission on Non-Ionizing Radiation Protection (ICNIRP) [84] for public exposure (833 mG). Location Directly over/below the cable/line 25m from the center of the ROW 50m from the center of the ROW 75m from the center of the ROW 100m from the center of the ROW 150m from the center of the ROW 250m from the center of the ROW 500m from the center of the ROW 800m from the center of the ROW

Cable Overhead line Magnetic Field (mG) Magnetic Field (mG) 81.0 55.0 3.7 39.1 0.3 11.0 0.1 5.0 0.0 3.0 0.0 1.0 0.0 0.4 0.0 0.1 0.0 0.0

Table 36. Magnetic field from EMF report (Appendix, Section 13)

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Table 36 shows that (a) the maximum magnetic field directly over the buried cable is 47% higher than immediately under the overhead line and (b) 50 metres away from the centre of the right of way the magnetic field of the buried cable has fallen 97% of that of the overhead line. The maximum magnetic field above the cable can prospectively be reduced to equal that of the overhead line by burying it at a greater depth, whilst keeping the spacing between cables constant. The disadvantage is that the dissipation of heat is less effective at greater depth and either the cables would have to be de-rated, or more cables installed. It has been recommended in Section 1.8.3.1 that in the Next Steps an ampacity study be performed to asses whether it would be possible to install the cables at a greater depth than 1.3 metres, by taking into account such parameters as the cyclic nature of the loading and the reduction in ground temperature at greater depth.

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DESIGNS PROPOSALS FROM PROSPECTIVE SUPPLIERS: SYSTEM DESIGN

CCI requested 15 prospective suppliers of cable systems (conventional cable and GIL) to submit technical designs and budgetary prices for the underground transmission system. They were sent the following documents:   

A Letter of Introduction from the AESO (see Appendix, Section 14) An inquiry document (see Appendix, Section 15) A questionnaire (see Appendix, Section 16.)

Manufacturers were initially requested to supply information by Sept 4th 2009. An extension was subsequently given until Sept 4th 2009. Because of the scope of the information requested, some suppliers did not provide information until Oct 13th. Further clarification questions were raised by CCI. The majority of manufacturers expressed interest and responded positively providing useful information. This included the provision of some of the photographs included within this document.

9.1

Inquiry and questionnaire documents

9.1.1

Inquiry document

The inquiry document comprised two parts: Part 1: Information to be provided  Experience with EHV cable systems  Proposed design of cable systems  Estimated costs  Repair period  Delivery period Part 2: Functional requirements  Timescale  Electrical System Design[1]  Load requirements  Route length  Nominal seasonal temperatures  Nominal ground thermal resistivities  Seasonal periods

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             

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Maximum cable design temperatures Installation design Description of the route Sheath bonding arrangement Depth of burial for conventional trench EMF limits for conventional trench Phase configuration for conventional trench Tunnel Reel length Tests 500 kV cable requirements 500 kV accessory requirements Other cables Major spares

[1] Notes: Suppliers were requested to base their proposals on both circuits being required to carry a continuous load of 3,000 MVA at 500 kV with both circuits loaded. It was later advised that the requirement was for 3,000 MVA with one circuit loaded only. The request to manufacturers was reviewed and it was determined that a reissue of the enquiry document would not be necessary as:  

9.2

The size of the cable and the number of cables per phase could not have been reduced as these are determined by the need for each circuit alone to carry 3,000 MVA. In principle the spacing between circuits used for the scoping study could have been reduced without reducing the ampacity at 1,500 MVA to less than 7 metres, this being the spacing between the Groups of Cable within each circuit. The spacing between groups of cables is determined by both thermal and circuit security considerations, as described in section 7.6 and section 7.7. Thus the minimum spacing between circuits could not be reduced to less than 7 metres.

Requests for technical information from prospective suppliers of 500 kV cable systems

CCI requested several prospective suppliers of 500 kV cable systems to provide technical recommendations for two parallel 500 kV cable circuits, each of a generic route length of 10 km. At the date of issue of the enquiry document the scenarios of 20 km, 65 km and those utilising GIS switching substations at the cable transitions had not been developed.

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They were told that a service life of 40 years would be required, and also that the cable should be suitable for continuous operation at approximately 525 kV as previous system studies had indicated that the voltage in areas where cable might be used were likely to be around this value. Whilst it was envisaged that each circuit would require multiple cables per phase, they were not given any instructions as to how many underground cables they should propose. In order for them to be able to prepare designs, they were given the following parameters: 

Nominal depth, seasonal temperatures and ground thermal resistivity    

Maximum ground temperatures: Summer 20°C Winter 0°C Ground thermal resistivity (when fully dried out) 3.0 K.m/W Backfill and normal ground thermal resistivity 0.9 K.m/W Depth to top of cable (for both cables in ducts or direct burial) 1.3 metres

The above depth, temperatures and ground thermal resistivities were based on those used in the design of the cable system for the recently installed Downtown Edmonton Supply and Substation 240 kV cable system. To give prospective suppliers an indication of the climatic conditions for which the cable systems must be designed, they were asked to base their recommendations on the following minimum temperatures: Ground at 1.3m depth for direct buried cable and joint design -10°C -15°C Air for duct- manhole system design: cable and joint -20°C -20°C Air within deep tunnels for cable and joint design -10°C -10°C Air within cut and cover tunnels for cable and joint design -20°C -20°C Outdoor air for cable and termination design -50°C -50°C Indoor air for cable and termination design -10°C -10°C (Note: the temperatures in italics are those that were recommended at the end of the feasibility study) 

Installation design Designs based on three types of installation were requested:   

Cables installed in duct-manhole system Cables direct buried in the ground Cables installed in tunnels

Prospective suppliers were not asked to propose designs of SCFF cable types for use in tunnels as these perceived to present too great a fire hazard. Prospective suppliers were not required to

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perform detailed ampacity calculations for their tunnel proposals, as, at this feasibility study stage, it was not considered necessary or appropriate to request multiple suppliers to perform the complex calculations necessary to prepare proposals for tunnel ventilation arrangements. 

Description of the route Prospective suppliers were advised that the cable route was anticipated to be in rural areas and were only asked to consider installation designs for cables installed at normal depths. At the time that the enquiries were sent to prospective suppliers there was insufficient information available about the types of obstructions that would have to be crossed for the prospective suppliers to be given clear guidance as to the types of obstructions that would have to be crossed. They were asked to provide proposals based on the cable route terminating into one or more of the following arrangements:    



Outdoor, air insulated terminations Indoor, air insulated terminations Outdoor SF6 terminations Indoor SF6 terminations

Sheath bonding arrangement Prospective suppliers were asked to prepare designs in which the sheath voltage, at maximum load, would not exceed 250 Volts.



Phase configuration for conventional trench For both cables installed in ductbanks or direct in the ground, prospective suppliers were asked to advise their dimensional recommendations for:  a horizontally flat spaced formation  any optional alternative configurations.



Reel lengths Prospective suppliers were advised that the maximum sizes of cable reels which can be delivered to site should be taken as:  

Reel overall diameter Reel gross weight

No greater than 4.3 metres No greater than 35 Tonnes

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At the time that the enquiries were sent to prospective suppliers the transportation survey had not been completed. The above limits are typical for road transportation in many countries. 

Tests Prospective suppliers were advised that the test requirements for XLPE cable systems would be generally in accordance with the requirements of IEC 62067[1] but that tests additional to those in IEC 62067[1], in particular to demonstrate the performance of the cable system at the minimum temperatures which could be encountered in cables and accessories for the Edmonton region of Alberta.



500 kV cable requirements Prospective suppliers were advised that XLPE cables must have a longitudinally water blocked conductor and be longitudinally water blocked under the metallic radial water barrier. XLPE cables for the following installation types must have:  a continuously extruded metallic sheath or a welded metallic sheath for cables direct buried in the ground or in duct-manhole systems:  a continuously extruded metallic sheath, a welded metallic sheath or a laminated metallic foil radial water barrier for tunnel systems



DTS fibres Prospective suppliers were advised that DTS (Distributed Temperature Sensing) fibres would be laid with the cables and that to give a useful indication of cable temperatures when installed in ducts, it is preferred that:  for XLPE cable the fibres would be included within the cable construction  proposals for DTS fibres external to the 500 kV cables and ducts would also be considered for XLPE and SCFF cables

9.3

System designs proposed by prospective suppliers

Most suppliers offered systems utilising two cables per phase with two Groups of Cables per circuit, in separated trenches fairly widely spaced apart as depicted in Figure 103. All suppliers offered naturally cooled systems. No supplier offered a system requiring only one group of cables per circuit, either with or without forced cooling.

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Figure 103. Underground cable: design requirement The circuits are designed to meet the contingency operation, shown in Figure 103. Either circuit must be able to carry a peak load of 3,000 MW when the other circuit is unavailable. The requirement is described in Section 2.1.1, Functional Requirement: Power Transmission. Each circuit comprises two groups of cable. Thus each group of underground cables must be designed to carry a peak load of 1,500 MW.

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Cables in Ducts Ground surface

Duct Cable Duct block

Phase spacing

Phase spacing

Group spacing

Phase spacing

Phase spacing

Cables direct buried in the ground Ground surface

Cable Backfill

Phase spacing

Phase spacing

Group spacing

Phase spacing

Phase spacing

Figure 104 Cable spacing To achieve the ampacity some suppliers proposed one or more of the following deviations from the design parameters:  a reduction in the depth  a reduction in the thermal resistivity of the ground, backfill or duct surround.

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Duct-Manhole systems

The phase spacing ranged from 450 mm to 1,300 mm, and the group spacing ranged from 2,500 mm to 7,000 mm. In general proposals with wider group spacing had narrower phase spacing. Proposals were also received for very closely grouped cables with all the cables required for one circuit being installed in a single duct block. This arrangement required three cables per phase using 3000 mm² conductors. Bentonite filling of the ducts was also proposed by some suppliers to achieve the required ampacity.

9.3.2

Direct buried systems

The phase spacing ranged from 350 mm to 1,000 mm, and the group spacing ranged from 2,500 mm to 6,000 mm. In general proposals with wider group spacing had narrower phase spacing. Proposals were also received for very closely grouped cables with all the cables required for one circuit being installed in a single trench. This arrangement required three cables per phase using 3,000 mm² conductors. Each circuit would consist of nine cables installed in a trench 3,500 mm wide.

9.3.3

Tunnel systems

For installation in tunnels, some suppliers proposed a reduced number of joints for cables installed in tunnels. Up to 30% fewer joints were proposed for cables installed in tunnels. Depending on the phase spacing, longer section lengths could result in higher sheath voltages. Higher sheath voltages could be considered for tunnel installations than for buried systems.

9.3.4

Sheath bonding systems

All XLPE and SCFF cable suppliers based their proposals on cross bonded cable sheath systems. A typical cross bonding arrangement is shown in Figure 105 and Figure 106.

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Figure 105. Cross bonding schematic

Figure 106. Detail of cross bonding components The number of joints to be supplied, and hence the length of cable on each reel, varied from supplier to supplier. The number of joints ranged from approximately 150 to over 300.

9.4

Designs proposals from prospective suppliers: cable Different cable types have been proposed by prospective suppliers. Most suppliers offered XLPE insulated cable designs, but some also offered SCFF cable types as an alternative. GIL (gas

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insulated line) was also offered. The supplier of HPFF (High pressure fluid filled) cable responded that they had no suitable product to offer for the 500 kV Heartland Project.

9.4.1

XLPE cable designs: general Cable designs have been provided by several manufacturers. The most commonly proposed arrangements were systems that would utilise two cables per phase to carry 3,000 MVA. These would be arranged as two groups of three single core cables, fairly widely spaced so as to reduce mutual heating effects. The features of the XLPE cables proposed for such a system are described below.

9.4.2

Conductors for XLPE cable designs All manufacturers have proposed cables with conductor designs of 2,500 mm², although a few manufacturers are able to offer larger conductors should they be needed. Most manufacturers proposed some kind of insulated wires in their conductor designs to reduce the AC resistance, increase transmission efficiency and thus reduce the power losses when carrying a given current.

9.4.3

Core design for XLPE cable designs Most manufacturers have offered an insulation thickness of around 30 mm. Cables with thinner insulation thickness have higher electrical field strength (stress) at the interface between the cable and the accessories. For EHV cables with large conductors it is generally the maximum permissible stress at this interface that limits the minimum thickness of insulation. Some manufacturers claimed lower dielectric losses than would have been calculated if the material properties listed in the recommended standard IEC 60287[83] had been used.

9.4.4

Sheath design for XLPE cable designs Manufacturers have offered a range of different types and these are shown diagrammatically in Figure 107, Figure 108, Figure 109, Figure 110, Figure 111, Figure 112 and Figure 113. In general it can be seen that cable designs incorporating lead sheaths (Figure 107 and Figure 111) are significantly heavier than other designs; cable designs with corrugated sheaths generally have larger overall diameters.

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The metallic shield or sheath over the insulated core has to provide:  a low impedance path for fault currents  a watertight radial barrier to prevent moisture reaching the insulation. The metallic shield can either be a single metallic layer which fulfils both these functions, or it can comprise two separate components, a layer of wires to carry the fault current, and a separate metallic layer to provide the water barrier. Both weight and diameter can limit the maximum length of cable that can be delivered to site as they will govern the overall weight and dimensions of the reels upon which the cables travel from the factory to the installation site. The weight of the cable can limit the maximum length that can be pulled in to a duct block. Heavier cables cannot be pulled in such long lengths as lighter cables. Manufactures also advised the ‘sheath losses’ for their designs, i.e. the sheath losses are dependent upon the design of the sheath (and also upon the phase spacing at which the cables are installed) According to the method for calculating ampacity described in IEC 60287[83], any losses in wire screens can be considered negligible. The losses in annular metallic sheaths tend to be higher in cables with lower sheath resistance. Thus cables with annular sheaths of low resistance aluminium have higher losses than those with higher resistance annular sheaths, although this is not so significant at wider phase spacing. The lowest loss type is that utilising a stainless steel sheath. Cables with lower losses can be laid in more compact formation, with lower external magnetic fields and lower induced sheath voltage. For cables to be installed in tunnels, where the cables will not be immersed in water, some manufacturers have offered cable designs with an overlapped or welded aluminium foil that is substantially thinner than the annular sheaths proposed for installation in duct-manhole or direct burial arrangements. These offer lower losses, lower weight and possibly reduced cost.

9.4.5

Distributed Temperature Sensing Cable designs incorporating a layer of wires can be modified to include optical fibres for DTS (Distributed Temperature Sensing) and several manufacturers have proposed cables of this type. Optical fibres can also be located in cable designs with metallic sheaths in between layers of cushioning/water blocking tapes, although no suppliers offered this. This is advantageous for cables installed in a duct manhole system, but not so significant for cables installed direct in the ground or in tunnels.

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DTS is described in Section 3 ‘Basic Description’.

9.4.6

Jacket design for XLPE cable designs All manufacturers have offered Polyethylene jackets for duct-manhole or direct burial arrangements. Jackets with superior fire performance have been offered for installation in tunnels.

9.4.7

SCFF cable designs A minority of manufacturers offered SCFF (Self contained fluid filled designs). Manufacturers have proposed cables with conductor designs of 2,500 mm² or 3,000 mm². Conductors with insulated wires have not been offered. All proposed designs of SCFF cable use LPP (Laminated Polypropylene Paper) and have an insulation thickness several mm less than that of XLPE. The overall diameter is thus less than that of the equivalently sized XLPE design. All proposed designs include corrugated aluminium sheaths and polyethylene jackets. designs of SCFF cables that incorporate lead sheaths have been proposed.

No

All manufacturers have offered Polyethylene jackets for duct-manhole or direct burial arrangements. SCFF cables are not generally considered suitable for installation in tunnels.

9.4.8

GIL design In addition to conventional, flexible, cable systems GIL has also been proposed. The state of the art together with significant applications of GIL is described in Section 4.10. GIL was offered for installation in a tunnel and budgetary prices were provided. GIL was not offered for direct burial in the ground. The GIL system design proposed by prospective suppliers for the 500 kV Study Project is substantially different to that of conventional, flexible, cable in the following ways: 

GIL design, Figure 115, is significantly larger in diameter than XLPE or SCFF cable types and thus it has been proposed that it would be delivered in straight

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



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sections and assembled together on site. The maximum length of each section would be approximately 10 metres. Each GIL tube is rated at 4,000 amps assuming that means exist to dissipate the heat into the ambient air. This is equivalent at 500 kV to 3,464 MVA, or 3,000 MW at a 0.865 power factor). Thus only one set of three phase tubes would be required per circuit. For two circuits six phases was offered. Previous GIL installations have not generally been buried in the ground; they have either been supported on structures above ground, or in underground tunnels.

The minimum phase spacing between phases would be 900mm.

9.4.9

Cable design types proposed The construction and approximate dimensions of the XLPE and SCFF cables proposed by prospective suppliers are shown diagrammatically in the following figures:         

Figure 107: Proposed 500 kV design: extruded lead sheath. Figure 108: Proposed 500 kV design: welded aluminium sheath. Figure 109: Proposed 500 kV design: corrugated aluminium sheath. Figure 110: Proposed 500 kV design: copper wire screen and corrugated stainless steel sheath. Figure 111: Proposed 500 kV design: copper wire screen and lead sheath. Figure 112: Proposed 500 kV design: wire screen and smooth aluminium sheath. Figure 113: Proposed 500 kV design: copper wire screen and aluminium laminate. Figure 114: Proposed 500 kV design: self contained fluid filled. Figure 115: Proposed 500 kV design: GIL

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500 kV Proposed Design 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, lead sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

Diagrammatic only Item Details 1 Copper conductor 2 Conductor binder 3 Extruded screen 4 XLPE Insulation 27-32 mm 5 Extruded screen 6 Water-blocking cushioning tapes 7 Extruded lead sheath 4-5 mm 8 Polyethylene Jacket with semi-conductive coating Approximate weight 55-60 kg/m Approximate diameter 150-160 mm Figure 107: Proposed 500 kV design: extruded lead sheath

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500 kV Proposed Design 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, smooth aluminium sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

Diagrammatic only Item Details 1 Copper conductor 2 Conductor binder 3 Extruded screen 4 XLPE Insulation 27-32 mm 5 Extruded screen 6 Water-blocking cushioning tapes 7 Smooth (welded) aluminium sheath 0.75-1.5 mm 8 Polyethylene Jacket with semi-conductive coating Approximate weight 38-40 kg/m Approximate diameter 145-155 mm Figure 108: Proposed 500 kV design: welded aluminium sheath

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500 kV Proposed Design 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, corrugated aluminium sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

Diagrammatic only Details Copper conductor Conductor binder Extruded screen XLPE Insulation 27-32 mm Extruded screen Water-blocking cushioning tapes Corrugated aluminium sheath 7 1.5-3.5 mm (extruded or welded) 8 Polyethylene Jacket with semi-conductive coating Approximate weight 40-42 kg/m Approximate diameter 155-170 mm

Item 1 2 3 4 5 6

Figure 109: Proposed 500 kV design: corrugated aluminium sheath

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500 kV Proposed Design 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, copper wire screen, corrugated stainless steel sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

9

10

Diagrammatic only Item Details 1 Copper conductor 2 Conductor binder 3 Extruded screen 4 XLPE Insulation 27-32 mm 5 Extruded screen 6 Water-blocking cushioning tapes 7 Distributed temperature sensing fibre 8 Copper wire screen 9 Corrugated stainless steel sheath 0.75-1.0 mm 10 Polyethylene Jacket with semi-conductive coating Approximate weight 45-47 kg/m Approximate diameter 160-170 mm Figure 110: Proposed 500 kV design: copper wire screen and corrugated stainless steel sheath

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500 kV Proposed Design 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, copper wire screen, lead sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

9

10

Diagrammatic only Item Details 1 Copper conductor 2 Conductor binder 3 Extruded screen 4 XLPE Insulation 27-32 mm 5 Extruded screen 6 Water-blocking cushioning tapes 7 Distributed temperature sensing fibre 8 Copper wire screen 9 Extruded lead sheath 2-3 mm 10 Polyethylene Jacket with semi-conductive coating Approximate weight 53-58 kg/m Approximate diameter 145-165 mm Figure 111: Proposed 500 kV design: copper wire screen and lead sheath

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500 kV Proposed Design 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, copper or aluminium wire screen, aluminium sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

9

10

Diagrammatic only Item Details 1 Copper conductor 2 Conductor binder 3 Extruded screen 4 XLPE Insulation 27-32 mm 5 Extruded screen 6 Water-blocking cushioning tapes 7 Distributed temperature sensing fibre 8 Copper or aluminium wire screen 9 Smooth (welded) aluminium sheath 0.5-1.0 mm 10 Polyethylene Jacket with semi-conductive coating Approximate weight 38-40 kg/m Approximate diameter 155-160 mm Figure 112: Proposed 500 kV design: wire screen and smooth aluminium sheath

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500 kV Proposed Design (for tunnel use only) 2500mm² Milliken stranded water-blocked copper conductor, XLPE insulation, single-core, copper wire screen, laminated aluminium sheath, Polymeric jacket 1

2

3

4

5

6

7

8

9

10

Diagrammatic only Item Details 1 Copper conductor 2 Conductor binder 3 Extruded screen 4 XLPE Insulation 27-32 mm 5 Extruded screen 6 Water-blocking cushioning tapes 7 Distributed temperature sensing fibre 8 Copper wire screen 9 Overlapped aluminium laminate 0.2-0.4 mm 10 Polymeric Jacket Approximate weight 35-43 kg/m Approximate diameter 145-150 mm Figure 113: Proposed 500 kV design: copper wire screen and aluminium laminate

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500 kV Proposed Design (SCFF) 2,500 or 3,000 mm² Milliken stranded copper conductor, LPP insulation, single-core, corrugated aluminium sheath, Polyethylene jacket 1

2

3

4

5

6

7

8

Diagrammatic only Item Details 1 Central fluid duct 2 Copper conductor 3 Conductor binder and screen 4 Impregnated LPP insulation 25-26 mm 5 Insulation screen and binder 6 Radial clearance 7 Corrugated Aluminium Sheath 3-4 mm 8 Polyethylene Jacket with semi-conductive coating Approximate weight 41 kg/m (2,500 mm²) to 48 kg/m (3,000 mm²) Approximate diameter 145 mm (2,500 mm²) -155 mm (3,000 mm²) Figure 114: Proposed 500 kV design: self contained fluid filled

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500 kV Proposed Design (GIL) Aluminium alloy conductor, SF6 insulation, Aluminium alloy enclosure

Cross section

Longitudinal section Diagrammatic only Item Details 1 Aluminium alloy conductor 2 Pressurised SF6 gas 3 Aluminium alloy enclosure 4 Support insulator Approximate weight 45 kg/m (average, includes insulators) Approximate diameter 550 mm Figure 115: Proposed 500 kV design: GIL

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9.5

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Cable electrical values provided by suppliers

Prospective suppliers of cable systems were asked to provide values of resistance, conductor and sheath losses, capacitance and dielectric losses. The averages of the appropriate values provided by the prospective suppliers were calculated and tabulated below. These were passed to AESO for use in the power flow studies and calculations of power loss performed by Teshmont. The results of their calculations are given in Appendix, Section 5. Table 37 shows the average cable capacitance and charging current provided for XLPE cable Capacitance per cable Charging current per cable at 500 kV Dielectric loss per cable at 500 kV (estimated) Dielectric loss per group of three single phase cables at 500 kV (estimated)

pF/m mA/m W/m W/m

213 23.1 5.2 15.6

Table 37 Supplier responses: Average capacitance and dielectric losses for XLPE cable Table 38 shows the average cable capacitance and charging current provided for SCFF cable Capacitance per cable Charging current per cable at 500 kV Dielectric loss per cable at 500 kV (estimated) Dielectric loss per group of three single phase cables at 500 kV (estimated)

pF/m mA/m W/m W/m

290 24.5 12.7 38.1

Table 38 Supplier responses: Average capacitance and dielectric losses for SCFF cable Table 39 shows the average capacitance and charging current provided for GIL Capacitance per cable Charging current per cable at 500 kV

pF/m mA/m

53 5.8

Table 39 Supplier responses: Average capacitance for GIL Table 40 shows the average and maximum combined conductor and sheath losses provided for XLPE cable.

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Conductor and Sheath losses at 1,500 MVA per group of cables at 500 kV Equivalent resistance per cable

W/m µΩ/m

103.6 11.5

Table 40 Combined conductor and sheath losses: XLPE cable – mean and maximum No complete system design utilising two SCFF cables per phase, and suitable for the transmission of 3,000 MVA per circuit, has been proposed. The power losses for a SCFF cable system have therefore not been analysed. Because an SCFF cable has higher dielectric losses than the equivalent XLPE insulated cable, the power losses at low transmitted loads would be higher for an SCFF cable than for an XLPE cable. Table 41 shows the combined conductor and enclosure losses provided for GIL. Conductor and enclosure losses at 3,000 MVA per 3-phase group of GIL Equivalent resistance per single phase GIL

W/m µΩ/m

105.8 11.8

Table 41 Conductor and enclosure losses of GIL

9.6

Splice designs proposed by prospective suppliers

Three different types of splice designs were offered for XLPE cables:  One piece silicone rubber prefabricated.  One piece EPR rubber prefabricated.  Prefabricated composite with EPR rubber stress cones The major electrical components of the proposed one piece joint (Silicone rubber or EPR rubber) and prefabricated composite joint offered are shown schematically in Figure 116 and in Figure 117

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Figure 116 One piece prefabricated joint (OPJ)

Figure 117. Prefabricated composite joint (PJ) More suppliers offered one piece prefabricated type joints than offered prefabricated composite type joints.

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10 TRANSITION STATION The technical details of the transition stations were complied by the HPT and are given in Appendix, Section 17 and 26. Transition station types:   

Scenarios 1 and 2 are air insulated switchgear (AIS) in the open air (-50oC design temperature). Scenarios 3 and 4 will be gas insulated switchgear (GIS) in a building. An example of gas insulated switchgear is shown in Figure 118. An indoor heated station is not included at this stage in the engineering work, but will be added to the Project Risks, Section 15 to cover the risk that the cable terminations will not operate at -50oC.

Figure 118. Indoor GIS switchgear Courtesy of Areva Reactor types and use:  

One three phase unit per group of three cables. The reactor is needed for line energisation and also has benefits in reducing the current loading on the cable. Reactors are positioned at both transition stations, one at each end of the underground cable, to allow for the requirement that the circuit can be energised from either end.

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

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A study has been performed to show the need for the reactor is needed in the circuit in normal loading and in circuit energisation, (reference Teshmont’s report in Appendix Section 5).

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11 POWER LOSSES The losses in an underground cable and overhead line are comprised of two parts: 

A ‘variable’ part that is dependent upon load current, this being the heating of the conductor by the flow of load current.



A ‘fixed’ part of constant magnitude that is independent of load current. The fixed losses are all a function of the applied system voltage which is constant irrespective of the loading.

The ratio of variable to fixed losses are different in underground cables and overhead lines: 

The ratio is high in an overhead line, as the overhead line possesses higher conductor resistance than a cable, but lower voltage related losses.



Conversely the ratio is low in an underground cable because the fixed losses of a cable are high. The fixed losses associated with a cable are:  Insulation losses in the XLPE insulation  Losses in the conductor due to the flow of charging current into the XLPE insulation  Insulation and conductor losses in the reactors

A ‘cross over’ load exists at which the losses in the cable are equal to the losses in the same length of overhead line.

11.1.1 Relationship of power loss to power transfer for the 500 kV Study Project Teshmont performed a system study for AESO, Appendix Section 5, and compared the losses for each of the scenarios. Each scenario has different lengths of overhead line and cable connected in series and has reactors connected in parallel. In consequence the scenarios have a modified ratio of variable to fixed losses. A comparison of one circuit of a 65 km all-cable scenario with an all overhead-line scenario in Figure 119 shows: 

The ‘cross-over load’ occurs at 1,700 MW at which the overhead line and underground cable scenarios have equal losses.



For transmitted loads up to 1,700 MW, the all-overhead line Scenario 6 has lower losses.

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

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For transmitted loads greater than 1,700 MW, the underground cable scenario has lower losses. However, a single circuit will only experience loads in excess of 1,500 MW in contingency situations in which the other circuit is un-available. Thus the prospective power loss benefits of XLPE underground cables are unlikely to be realised in the 500 kV Study Project.

Figure 119. Power losses for selected scenarios at different levels of transmitted power At loads less than the 1,700 MW ‘cross over’ load, the scenarios containing a portion of cable have a higher loss than Scenario 6, which is all-overhead line. The difference in losses compared to the overhead line Scenario 6 is lowest in those scenarios that contain a) the shortest length of cable and b) the fewest number of Groups of Cables. Figure 119 shows that:

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

Scenario 2A.10 has slightly higher losses than the overhead line Scenario 6. This is because Scenario 2A.10 contains the smallest quantity of cable. It is the first stage of a staged option and comprises one group of cables (per circuit) instead of two. Note that the losses for Scenario 2A.10 are only plotted up to 1,500 MW as this is the limiting load for a single Group of Cables.



Scenario 1A.10 comprises two Groups of Cables and so has a load capability under contingency operation of 3,000 MW. The losses in Scenario 1A.10 above 1,700 MW are less than those of the overhead line Scenario 6 because variable losses in the overhead line conductor are greater than those in the underground cable conductor.



Scenario 5.B.65 comprises two Groups of Cables of 65 km length. The two Groups of Cable, under contingency operation, have a load capability of 3,000 MW:  At 3,000 MW the losses in the cable Scenario 5B.65 are 16 MW compared to 28 MW in the overhead line Scenario 6.  At a nominal low load of, say, 400 MW the losses in the cable Scenario 5B.65 are 6 MW, compared to 0.5 MW in the overhead line Scenario 6.

11.1.2 Cumulative power losses for the 500 kV Study Project Teshmont calculated the losses for each scenario for 40 years based on the forecast average loads as follows: Up to and including 2026: 2027 and beyond:

457.3 MW 1,000.0 MW

For the average load of 457.3 MW in the period up to and including 2026 , the average power losses for the relevant scenario Stages are presented in Table 42 and Figure 120.

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Scenario

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Scenario condition for the loss calculation 2 Groups of Cables per circuit (Un-staged) 1 Group of Cables per circuit (Stage 1 only) 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) 1 Group of Cables per circuit (Stage 1 only)

Total loss

1A.10 2A.10 3A.10 4A.10

Length km 10 10 10 10

1B.20 2B.20 3B.20 4B.20

20 20 20 20

2 Groups of Cables per circuit (Un-staged) 1 Group of Cables per circuit (Stage 1 only) 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) 1 Group of Cables per circuit (Stage 1 only)

2.4 1.7 1.7 1.7

5A.65 5B.65

65 65

1 Group of Cables per circuit 2 Group of Cables per circuit

3.4 6.5

6

65


1.0

MW 1.7 1.4 1.4 1.4

Table 42. Power losses for each scenario at an average load of 457.3 MW Key to the Figure 120 bar chart : Yellow: All-overhead line i.e. Scenario 6. Green: One Group of Cables in operation, i.e. 2A.10, 2B.20, 3A.10, 3B.20, 4A.10, 4B.20 and 5A.65. Blue: Two Groups of Cable in operation, i.e. the un-staged Scenarios 1A.10, 1B.10 and 5B.65.

Figure 120. Power losses for an average load of 457.3 MW For the average load of 1,000 MW for the period 2027 and beyond, the average power losses for the relevant scenario Stages are presented in Table 43.

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1A.10 2A.10 3A.10 4A.10

Length km 10 10 10 10

Scenario condition for the loss calculation 2 Groups of Cables per circuit (Un-staged) Stage 1 not applicable, Stage 2 identical to scenario 1 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) Stage 1 not applicable, Stage 2 identical to scenario 3

MW per circuit 3.9 3.7 -

1B.20 2B.20 3B.20 4B.20

20 20 20 20

2 Groups of Cables per circuit (Un-staged) Stage 1 not applicable, Stage 2 identical to scenario 1 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) Stage 1 not applicable, Stage 2 identical to scenario 3

4.4 4.0 -

5A.65 5B.65

65 65

Not applicable 2 Group of Cables per circuit

7.1

6

65


3.5

Total loss

Table 43. Power losses per circuit for each scenario at an average load of 1,000 MW

11.1.3 Estimated Net Present Value of Losses The estimated Net Present Value (NPV) cost of the energy losses taken over the forty year analysis period is given in Appendix, Section 3 and is summarised in Table 44. The estimated Net Present Value (NPV) of losses for the 40 year period is summarised in Table 44 and shows that:  The estimated NPV of the losses for all scenarios ranges from 33 $M (Scenario 6, alloverhead line) to 52 $M (Scenario 1.B.20). 

The estimated NPV of the losses is 7.3% of the estimated NPV Revenue Requirement* for Scenario 6, all-overhead line, and between 4.2 and 4.7% of the NPV Revenue Requirement for the scenarios that include cable. *Present Value of capital and maintenance costs, etc, as detailed in Appendix, Section 3

The estimated Net Present Value (NPV) of differences in losses between those of the scenarios containing cable and the all-overhead line Scenario 6 are also given in Table AB. These show: 

The difference in estimated NPV of the losses for all scenarios ranges from 5 $M (Scenario 3A.10) to 19 $M (Scenario 1.B.20).



The difference in estimated NPV of the losses as a percentage of the estimated NPV Revenue Requirement ranges from 0.6% (Scenario 3A.10) of to 1.6% (Scenario 1.B.20).

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Scenario

Staged

1A.10

No

2A.10

Yes

3A.10

No

4A.10

Yes

1B.20

No

2B.20

Yes

3B.20

No

4B.20

Yes

5A.65 5B.65 6

No

Description

2 Groups of Cables per circuit (Un-staged) 2 Groups of Cables per circuit (Stage 1 and Stage 2) 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) 1 Group of Cables per circuit (with two Groups out of three in operation) 2 Groups of Cables per circuit (Un-staged) 2 Groups of Cables per circuit (Stage 1 and Stage 2) 1 Group of Cables per circuit (Un-staged, with two Groups out of three in operation) 1 Group of Cables per circuit (with two Groups out of three in operation) All Cable All Cable All-overhead

ER 381

19th February 2010 UGC

OHL

Route

km

km

km

Estimated NPV Revenue Requirement $M

Estimated NPV of losses

Estimated NPV Loss difference from OHL

$M

%

$M

%

10

55

65

756

42

4.7

9

1.0

10

55

65

727

40

4.5

7

0.8

10

55

65

696

38

4.6

5

0.6

10

55

65

691

39

4.7

6

0.7

20

45

65

1,020

52

4.3

19

1.6

20

45

65

951

47

4.0

14

1.2

20

45

65

886

43

4.1

10

1.0

20

45

65

865

44

4.2

11

1.0

65 65 0

0 0 65

65 65 65

Ref

Ref

380

Table 44. Estimated NPV of power losses over a forty year period. NPV is the net of PV of losses and PV of Revenue requirement.

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Not calculated Not calculated 33 7.3




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12 GENERIC COST STUDY FOR THE 500KV STUDY PROJECT (Note: all costs in this report are in Canadian dollars, unless otherwise stated. All capital costs are in 2009 dollars). The estimated capital cost for the underground part of the 500 kV Study Project has been derived from anticipated price level information from prospective suppliers of 500 kV XLPE cable together with estimates of the civil construction costs, which were supplied by the HPT. For the total route length of 65 km, the estimated costs supplied by the HPT also include the overhead line and the associated transmission equipment, such as sub-stations, transition stations and reactive compensation.

12.1 Cable system unit costs The cable manufacturers’ indicative budgetary prices for the 10 km underground route length for the Heartland Project cable system have been analysed by CCI. For the purposes of commercial anonymity and competiveness the summarised costs have been made non-attributable to individual manufacturers. In order to calculate the cable system costs for each scenario of the 500 kV Study Project, the budgetary prices were analysed into average unit costs: 

   



Average cost of cable system per km of each Group of Cables, including supply of 3 km of cable (i.e. sufficient single core cable for one kilometre of a Group of Cables in a single trench), splices, jointing, bonding equipment, ancillary equipment, and supervision of cable laying, delivery to Edmonton. Average cost per termination of each Group of Cables, including 3 terminations, jointing, bonding equipment, ancillary equipment, delivery to Edmonton Average cost per commissioning test for each Group of Cables Average cost per set of development tests per supplier, including prequalification tests, type tests, and an allowance for low temperature tests Average cost per set of type tests per supplier. In the event of a staged installation, repeat type tests would be performed prior to the implementation of stage 2. In the intervening period between Stage 1 and Stage 2, there may have been minor changes to materials, manufacturing processes, etc, necessitating repeat type testing. Average cost per set of spares per supplier, including cable, splices and terminations.

From these the capital cost estimate of the cable system for each scenario was calculated and incorporated by HPT into the total capital cost estimate for each scenario.

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12.2 End-to-end estimated capital costs for the 65 km route length HPT compiled the total estimated capital costs for the 65 km long, 500 kV Study Project. Costs were estimated for nine scenarios, comprising different proportions of cable and overhead line. Four of the scenarios were formulated to have reduced quantities of cable and are referred to as staged options. These scenarios would initially be installed and operated with a reduced transmission capability; this is referred to as Stage 1. At a later date additional Groups of Cables would be installed to Stage 2 of these scenarios include the subsequent achieve the full 3,000 MVA transmission capability. The estimated capital cost of both stages was calculated. The estimated costs were based on the design information summarised in Appendix, Sections 17, 18, 19, 20, 21, 22 and 23. The total costs comprised:        

Cable system components (cable, terminations, joints and ancillaries) and jointing (CCI) Spares (CCI/HPT) Underground cable civil works (HPT) Cable installation into the ground, (HPT) Overhead line components and assembly (HPT) Transition station construction and equipment, such as reactors (HPT) Works and equipment in two substations (HPT) Owner’s costs (HPT)

The detailed estimated capital costs are given in Appendix, Section 2. A summary of the estimated capital costs for each scenario is given in Table 45.

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19th February 2010

Scenario

Staged

Description

UGC

OHL

Route

Stage 1

Stage 2

Total

1A.10 2A.10 3A.10 4A.10

No Yes No Yes

4 trenches (2 per phase), all installed together 4 trenches (2 per phase), 2 installed first and 2 later. 3 trenches, all installed together 3 trenches, two installed first and 1 later

km 10 10 10 10

km 55 55 55 55

km 65 65 65 65

$M 574 606

$M 201 105

$M 748 775 687 711

1B.20 2B.20 3B.20

No Yes No

4 trenches (2 per phase), all installed together 4 trenches (2 per phase), 2 installed first and 2 later. 3 trenches, all installed together

20 20 20

45 45 45

65 65 65

689 -

350 -

1014 1039 877

4B.20

Yes

3 trenches, two installed first and 1 later

20

45

65

720

185

905

6

No

0

65

65

-

-

382

All-overhead line

Table 45. Capital cost estimates for each scenario (2009 dollars)

12.3 Capital cost estimates: comparison of components in each scenario The breakdown of estimated capital cost components is shown in the following: Scenario 1A.10 and 2A.10 Scenario 3A.10 and 4A.10 Scenario 1B.20 and 2B.20 Scenario 3B.20 and 4B.20 Scenario 6 (All overhead line)

Figure 121 Figure 122 Figure 123 Figure 124 Figure 125

NOTE: The diagrams only show half of the route for clarity; the values represent the total estimated capital costs for the entire 65 km route.

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19th February 2010

Estimated capital costs for 4 groups of Cables, 10 km long

Stage 1 estimated costs are given in white on blue. Stage 2 estimated costs are given in black above red. Total estimated costs for each component are the sum of the Stage 1 and Stage 2 costs Figure 121. Estimated capital cost components in $M for 4 groups of Cables, 10 km long

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19th February 2010


Stage 1 estimated costs are given in white on blue. Stage 2 estimated costs are given in black above red. Total estimated costs for each component are the sum of the Stage 1 and Stage 2 costs. Figure 122. Estimated capital cost components in $M for 3 groups of Cables, 10 km long

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19th February 2010

Estimated capital costs for 65 km overhead line

Figure 125. Estimated capital cost components in $M for all overhead line (Scenario 6)

12.4 Estimated Net Present Value of the life cycle costs for the 65 km route length The estimated Net Present Value of the lifecycle costs were compiled by the AESO for the ‘end to end’ estimated capital costs, maintenance and spares are given in Appendix, Section 3, for the 500 kV Study Project route length of 65 km. A summary of the estimated NPVs for each scenario is given in Table 46.

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Scenario

Staged

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19th February 2010 Description

1A.10 2A.10

No Yes

3A.10 4A.10

No Yes

1B.20 2B.20

No Yes

3B.20 4B.20

No Yes


6

No

All-overhead

UGC

OHL

Route

PV Revenue Requirement

PV Losses

NPV Net Cost

km 10 10

km 55 55

km 65 65

$M 756 727

$M 42 40

$M 798 767

10 10

55 55

65 65

696 691

38 39

733 730

20 20

45 45

65 65

1,020 951

52 47

1,072 997

20 20

45 45

65 65

886 865

43 44

928 909

0

65

65

380

33

412


Table 46. Estimated NPV of the life cycle cost for each scenario

12.5 Comparison of the cost of each scenario The effect on cost of the number of Groups of Cable and of staging is shown in Table 47 and Table 48. Although the scenarios which have three Groups of Cables, rather than four, have lower cable cost, they have additional transition station costs because of the need for switchgear to rapidly switch between the Groups of Cables in a contingency situation. The scenarios with four Groups of Cables are permanently connected and available.

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Cable length km

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19th February 2010


Estimated capital costs

Estimated NPV of Life Cycle costs Un-staged Staged $M $M

Un-staged $M

Staged $M

4

748 (1A.10)

775 (2A.10)

798 (1A.10)

767 (2A.10)

3

687 (3A.10)

711 (4A.10)

733 (3A.10)

730 (4A.10)

Difference

-61

-64

-65

-37

4

1,014 (1B.20)

1,039 (2B.20)

1,072 (1B.20)

997 (2B.20)

3

877 (3B.20)

905 (4B.20)

928 (3B.20)

909 (4B.20)

Difference

-137

-134

-144

-88

10

20

Table 47. Effect on estimated cost of number of Groups of Cables

Cable length km


Estimated capital costs

Estimated NPV of Life Cycle costs Un-staged Staged Difference $M $M $M

Un-staged $M

Staged $M

Difference $M

4

748 (1A.10)

775 (2A.10)

+27

798 (1A.10)

767 (2A.10)

-31

3

687 (3A.10)

711 (4A.10)

+24

733 (3A.10)

730 (4A.10)

-3

4

1,014 (1B.20)

1,039 (2B.20)

+25

1,072 (1B.20)

997 (2B.20)

-75

3

877 (3B.20)

905 (4B.20)

+28

928 (3B.20)

909 (4B.20)

-19

10

20

Table 48. Effect on estimated cost of staging

12.6 Differences between the estimated cost of underground cable and overhead line Table 49 compares the estimated capital cost and the estimated NPV of the life cycle cost: 

Total estimated costs for each scenario

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    

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19th February 2010

Estimated cost differences for each scenario compared to all-overhead line (Scenario 6) Estimated cost ratios for each scenario compared with the all overhead line (Scenario 6) Average estimated costs of the 10 km and 20 km scenarios Average of the 10 km and 20 km scenarios’ estimated cost differences compared with alloverhead line (Scenario 6) Average estimated cost ratios compared to all overhead line, for the 10 km and 20 km scenarios Scenario

Estimated capital cost Estimated NPV of Life Cycle costs cost $M delta $M ratio cost $M delta $M ratio

1A.10

748

366

2.0

798

386

1.9

2A.10

775

393

2.0

767

355

1.9

3A.10

687

305

1.8

733

321

1.8

4A.10

711

329

1.9

730

318

1.8

Average of all 10 km scenarios

730

348

1.9

757

345

1.8

1B.20

1,014

632

2.7

1,072

660

2.6

2B.20

1,039

657

2.7

997

585

2.4

3B.20

877

495

2.3

928

516

2.3

4B.20

905

523

2.4

909

497

2.2

Average of all 20 km scenarios

959

577

2.5

977

565

2.4

6

382

0

1

412

0

1

Table 49. 500 kV Study Project Estimated costs, cost differences and cost ratios compared to all-overhead line Table 50 compares, for information only, the ratio of the estimated installed cost of 10 km and 20 km of underground cable to that of equal lengths of overhead line, excluding all other equipment. The values in Table 50 are derived from Table 3 of Appendix, Section 3.

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Scenario number

1A.10 / 1B.20 2A.10 / 2B.20 3A.10 / 3B.20 4A.10 / 4B.20

ER 381

19th February 2010 Number of Groups of Cable

4 2 + 2 (staged) 3 2 + 1 (staged) Average

Estimated cost ratio (installed underground cable to overhead line) 10 km underground 20 km underground 7.3 7.0 7.9 7.2 5.6 5.3 6.1 5.6 6.5

Table 50. Ratio of estimated installed cost of underground cable to an equal length of overhead line An example of how these ratios have been obtained is given below for Scenario 1B.20 (20 km): From column 2 of Table 3 given in Appendix, Section 3 the Transmission line estimated costs, i.e. excluding all other associated costs, are 205 $M for Scenario 6 (overhead) and 582 $M for Scenario 1B.20. The average overhead line estimated cost per km can thus be taken as 205 $M / 65 km = 3.15 $M/km Scenario 1B.20 includes 45 km of overhead line, the estimated cost of which can therefore be assumed to be some 3.15 $M/km x 45 km = 141.9 $M. Subtracting this from the total of 582 $M leaves 440.1 $M which relates to the estimated cost of 20km of cable. The cable estimated cost per route km is thus 440.1$M / 20km = 22 $M/km. The estimated cost ratio of underground cable to overhead line is therefore = 22 / 3.15 = 7.0. Table 51 shows the estimated cost ratio of installed cable, transition stations and additional telecommunication equipment to overhead line. This is also derived from Table 3 of Appendix, Section 3. Scenario number

1A.10 / 1B.20 2A.10 / 2B.20 3A.10 / 3B.20 4A.10 / 4B.20

Number of Groups of Cable 4 2 + 2 (staged) 3 2 + 1 (staged) Average

Estimated cost ratio (installed underground cable to overhead line) 10 km underground 20 km underground 9.8 8.6 10.5 8.9 8.3 6.9 8.9 7.3 8.7

Table 51. Ratio of estimated cost of underground cable and transition stations to an equal length of overhead line

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The cost studies, summarised in Table 49, Table 50 and Table 51 show that for the 65 km 500 kV Study Project: 

The estimated NPV of life cycle costs are greater than the estimated capital costs; however the cost ratio for each scenario compared to the all-overhead line scenario is not significantly changed.



The average ratio of installed cable cost estimates, to those of an equal length of overhead line is:  6.5 : 1 excluding all other equipment.  8.7 : 1 including transition stations and associated other equipment.



The average ratio of NPV of life cycle cost estimates for the 65 km route length with and without underground cable is:  1.8 : 1 for a 10 km cable length.  2.4 : 1 for a 20 km cable length.



Increasing the length of underground cable from 10 km to 20 km, increases the average estimated capital cost by 229 $M.



The lowest cost cable scenario for estimated capital cost is Scenario 3A.10 for the 10 km underground route length. Scenario 3A.10 comprises three Groups of Cables. The ratio of estimated cost to an all-overhead scenario (Scenario 6) is 1.8:1 and the estimated capital cost difference is 305 $M. The estimated cost of Scenario 4A.10 is closely similar, but higher with estimated capital cost and lower estimated NPV of life cycle costs . * Note: Scenarios 3A.10* has a less substantial n-1 redundancy margins than other 10 km scenarios to meet the contingency condition of 3,000 MW, as two Groups out of the three available in the fully staged options are required.



If four Groups of Cables* are used (scenario is 1A.10) the ratio of estimated cost to an alloverhead scenario (Scenario 6) is 2:1 and the estimated capital cost difference is 366 $M. * Note: Scenario 1A.10 has a more substantial n-1 redundancy margin to meet the contingency condition of 3,000 MW, as it comprises four Groups of Cables (two Groups out of the four being required).

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

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19th February 2010

There is a reduction in the estimated NPV of life cycle costs for staged installation. The reductions are: - Staged Scenario 2A.10 to un-staged Scenario 1A.10: 3.9% (31 $M) - Staged Scenario 4A.10 to un-staged Scenario 3A.10: 0.4% ( 3 $M) - Staged Scenario 2B.20 to un-staged Scenario 1B.20: 7.0% (75 $M) - Staged Scenario 4B.20 to un-staged Scenario 3B.20: 2.0% (19 $M)

12.7 Sensitivity studies on the estimated capital cost of the cable system 12.7.1 Sensitivity: Effect on cost of SCFF cable The estimated increase in the capital cost if SCFF cable is used in place of XLPE is given in Table 52. This is based on there being two SCFF cables per phase. Table 52 includes only cost differences for the supply and jointing of the cable system and does not include any differences which there may be in the installation costs. Scenario

Staged

1A.10 2A.10

No Yes

3A.10 4A.10

No Yes

1B.20 2B.20

No Yes

3B.20 4B.20

No Yes

Description

4 trenches (2 per phase), all installed together 4 trenches (2 per phase), 2 installed first and 2 later. 3 trenches, all installed together 3 trenches, two installed first and 1 later 4 trenches (2 per phase), all installed together 4 trenches (2 per phase), 2 installed first and 2 later. 3 trenches, all installed together 3 trenches, two installed first and 1 later

UGC

OHL

Route km

Stage 1 $M

Stage 2 $M

km

km

10 10

Total Change

55 55

65 65

+7

+7

$M +12 +13

10 10

55 55

65 65

+6

+3

+9 +10

20 20

45 45

65 65

+12

+12

+24 +24

20 20

45 45

65 65

+12

+6

+18 +18

Table 52. Estimated capital cost increase if SCFF cable is used

12.7.2 Sensitivity: Canadian Dollar value falls against other currencies by 20% Cable systems would be imported into Canada and the price would thus be dependent upon the exchange rate between the Canadian dollar and the native currency of the supplier. A fall in the value of the Canadian Dollar would result in an increase in the price of the cable system; a rise in the value of the Canadian Dollar would result in a fall in the price of the cable system. The historic variation in the value of the Canadian Dollar against other currencies over the past four years is shown in Figure 126. This shows that the value of the Canadian Dollar has fallen significantly against the value of the Japanese Yen, particularly in the period between 22 Feb 2008 and 6 July 2008. Exchange rates could

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19th February 2010

vary again between the time that the prospective suppliers prepared their indicative budgetary prices and the time that they submit commercial quotations.

1.2

140

1.0

120

USDollar Euro

80 0.6 60 0.4

Japan Yen

100

0.8

40

0.2

20

0.0

0

28/05/2005 10/10/2006 22/02/2008 06/07/2009 18/11/2010 USD

Euro

JPY

Figure 126. Historic variation in the value of Canadian dollar Table 53 shows the effect that a 20% change in the value of the Canadian Dollar would have on the cost of each of the scenarios.

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Scenario

Staged

1A.10 2A.10

No Yes

3A.10 4A.10

No Yes

1B.20 2B.20

No Yes

3B.20 4B.20

No Yes

ER 381

19th February 2010 Description


UGC

OHL

Route km

Stage 1 $M

Stage 2 $M

km

km

10 10

Total Change

55 55

65 65

12

11

$M 23 24

10 10

55 55

65 65

12

6

17 18

20 20

45 45

65 65

22

21

44 43

20 20

45 45

65 65

22

11

33 33

Table 53. Estimated capital cost change if Canadian dollar value should vary by 20%

12.7.3 Sensitivity: Metal prices change by 50% Suppliers commonly include a price variation clause in their commercial offers for cable systems, which allows them to increase or decrease the price to allow for any changes in the value of the metals in the cable between the time of their offer, and the time that the order is placed. The price changes given in Table 53 exclude the value of the metals in the cable, i.e. the metal prices in Canadian dollars are assumed to remain unaltered. Any variation in the cable price as a result of a change in the metal prices, as quantified in Section 12.7.3, would therefore also be added or subtracted from the cost of the project in addition to the changes given in Table 53. Cables contain copper, also lead and/or aluminium. Of these, the copper content is the most significant; a 2,500 mm² conductor weighing approximately 23 kg per metre. The price paid for cable systems is generally based on the metals price at the time that the order is received by the supplier. The price of copper can fluctuate significantly. The price in October 2005 was around 4.0 USD per kg, since then it has risen to approximately 9.0 USD per kg on several occasions. For illustration, the historic variation in copper prices in US Dollars, as published by the London Metal Exchange, over the past two years is shown in Figure 127.

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Figure 127. Historic variation in copper price (USD) Any change in the price of the metals used in the cables would thus have an effect on the price that the supplier would charge for the cables. If the metal prices should rise then the capital cost would increase, similarly if the metal prices should fall then the capital cost would fall. The estimated change in the capital cost if the price of the metals used in the cable should change by 50% is given in Table 54 for each of the scenarios. Scenario

Staged

1A.10 2A.10

No Yes

3A.10 4A.10

No Yes

1B.20 2B.20

No Yes

3B.20 4B.20

No Yes

Description


UGC

OHL

Route km

Stage 1 $M

Stage 2 $M

km

km

10 10

55 55

65 65

7

7

$M 12 13

10 10

55 55

65 65

6

3

9 10

20 20

45 45

65 65

12

12

24 24

20 20

45 45

65 65

12

6

18 18

Table 54. Estimated capital cost change if cable metal prices should vary by 50%

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13 500 kV STUDY PROJECT DURATION The total times to procure, test and install the 500 kV Study Project were compiled by HPT a) from times supplied by the suppliers for cable manufacture and b) for the civil installation and construction durations. The work items are listed in Section 13.1 and 13.2 and the AltaLink & EPCOR schedule basis is given in Appendix, Section 4. The estimated duration and ISD (in service dates) are given in Table 55. The dates and durations for the staged options refer only to the stage 1 of each scenario. Each of the dates given are for the supply and installation of all the equipment required for the particular scenario, including both cable and overhead line. The schedule was based on activities starting on February 01, 2010. As this date regresses, the ISD will also regress. Cable Length


km 4/2 10

0

Un-staged Time Scenario November 1, 2014 1A.10 57 months

November 1, 2014 57 months November 1, 2014 4/2 57 months November 1, 2014 3/2 57 months All Overhead Line March 29, 2013 3/2

20

In Service Date and Duration

3A.10 1B.20 3B.20 -

Staged Time December 1, 2013 46 months December 1, 2013 46 months November 1, 2014 57 months November 1, 2014 57 months -

Scenario 2A.10 4A.10 2B.20 4B.20 -

Table 55. Duration of cable supply and installation for each scenario The draft project schedules, summarised in Table 55, show that:  

The two 10 km long scenarios with two Groups of Cables to be installed in stage 1 have a cable supply and installation time of 46 months. All other scenarios have a cable supply and installation time of 57 months.

The project schedule includes estimates for the duration of the following work items:

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13.1 Cable 

  

  

Supply lead time including:  Low temperature development test  One year IEC62067[1] Prequalification test  Type test, generally to IEC62067[1]:  Cable manufacturing time (varies with the number of suppliers utilised) Cable shipping time to port of entry Preparatory civil works Cable delivery from the port of entry to Edmonton - Cable laying - Cable jointing - Joint bay setting-up and clearing-up Joint bay checks Civil reinstatement of joint bays Commissioning time:  Insulation tests, HV AC and PD at each joint  Set up of test vehicle and HV connections  Set up of PD connections to each joint  A separate test on each single core cable Group of Cables  Preliminary analysis of PD results  Contingency for the repetition of PD measurements  Dismantling of HV test equipment including PD connections to each joint:  Test weather window contingency:  Cable parameter measurements  Grounding system tests  Joint bay and link box grounding system tests  DTS system tests  Route marker checks  Grounding conductors checks  Link box checks

13.2 Transition station     

Equipment supply lead time Preparatory civil works time Equipment delivery time Equipment installation time Civil reinstatement time

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

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Commissioning time

14 UNDERGROUNDING THE ENTIRE 65 KM ROUTE LENGTH In addition to the eight underground scenarios considered in detail, some consideration has also been given to the implications if the entire 65 km route length were to be undergrounded. This mainly consists of the system studies conducted by Teshmont and described in Appendix, Section 5.

14.1 Scenarios considered If underground cable were to be used for the entire 65 km route length of the 500 kV Study Project, then scenarios, similar to those considered for 10 km and 20 km underground route lengths could be considered. However, as the undergrounding of 65 km is not being considered in such detail, the studies are limited to Scenario 5A.65, comprising one Group of Cables per circuit and shown in Figure 13, and Scenario 5B.65, comprising two Group of Cables per circuit and shown in Figure 14.

14.2 Technical limitations 14.2.1 Voltage control The voltage along very long lengths of cable can vary as load is applied or removed. Teshmont have considered this and their report is in Appendix, Section 5. Studies on switching have not been conducted. Such studies could be included as part of the next steps in the development of the 500 kV Study Project if required.

14.2.2 Reduction in useful power transmission capacity because of cable charging current Whenever cable insulation is subjected to a voltage, an electric current flows into the cable insulation. This current is referred to as the Charging current. This Charging current flows through the cable terminations, along the cable conductor and into the insulation. The following example is given to demonstrate the effect. The linear apportionment of charging current with length is correct. Every kilometre of 500 kV XLPE cable of the type that would be selected for the 500 kV Study Project would have a charging current of about 23.1 amps. (This is based on the technical information provided by prospective cable suppliers and is shown in Table 37.) 23.1 amps is 1/75th of the maximum current carrying capacity (ampacity) of the cable conductor of 1,732 amps. Similarly for 2 km of cable, the charging current would be 46.2 amps, or 2/75ths of the ampacity. The effect of this

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charging current flowing in the conductor is negligible for short lengths of cable, but becomes more important if the length increases, and the limiting case is when the total charging current reaches 75/75ths. In this case all the current carrying capacity of the conductor would be used to carry the charging current with no spare capacity available to carry any useful current to the load. To avoid overheating the cable the total current in the conductor cannot exceed its ampacity. The useful power that can be carried by the cable is thus reduced by the need to carry the charging current as well as the useful current to the load. It is the charging current that makes a very long AC cable unviable. This is one of the main reasons why very long cables, for example undersea interconnectors, utilise DC rather than AC transmission systems. For a 65 km cable length for the 500 kV Study Project, the total charging current would be 65/75ths (i.e. 87%) of the ampacity. The reader is cautioned that the calculation of the useful load current that can be carried is not a simple linear subtraction. The calculation and its explanation are beyond the scope of this report, but the results, based on a maximum cable ampacity of 1,732 amps, and a charging current of 23.1 amps per km, are as follows:  65 km with no reactor: The useful load current would be 863 amps, a reduction of 50%.  65 km with a reactor at the circuit end: The useful load current would be 1,562 amps, a reduction of 10%. Further reductions in the charging current flowing in the cable conductor could be made if ‘reactive’ compensation is also added along the length of the cable route. This would require that Substations containing the reactive compensation be constructed at one or more positions along the route. Teshmont have studied the effects of cable capacitance on power demand and voltage control for a 65 km cable length (Scenarios 5A.65 and 5B.65) and their report is in Appendix, Section 5.

14.3 Supplier capability To underground 65 km of EHV, high ampacity, cable would be a significant undertaking. There are currently only about a dozen manufacturers who may be able to provide 500 kV, large conductor, cable systems of the type which would be required for the 500 kV Study Project. Not all of these have any experience of supplying 500 kV cable systems. By way of comparison, the largest 500 kV project previously installed was the 40 km route in Tokyo which comprised six parallel cables. This used a total of 240 km of 500 kV, 2,500 mm2 conductor cable. This was supplied by four manufacturers, each supplying approximately 60 km of single core cable to construct the 40 km double circuit route. The Tokyo project was completed in approximately nine years, including testing, manufacturing and installation. Since the time of the Tokyo project, there has been some reduction in the number of independent EHV cable manufacturers and, the four Japanese manufacturers who supplied cable for the Tokyo project have now been consolidated into two. If the entire 65 km of the 500 kV Study Project were to be undergrounded, with four Groups of Cables, the quantity of cable required would be 780

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km. This means that the quantity of cable and accessories would exceed that of the Tokyo project by a factor of 3.25.

14.4 Cost estimates Detailed cost estimates were not prepared for an underground cable route length of 65 km. Some indication of cost can be obtained by extrapolation of the detailed costs from the Appendices for the scenarios with underground route lengths of 10 km and 20 km.

14.5 Cable system fault statistics for 65 km underground route length Using the same methodology as been applied to the scenarios with 10 km or 20 km route lengths, the unconditioned and conditioned failure rates shown in Table 25 and Table 27 have been applied to a 65 km underground route length for the 500 kV Study Project. The results are given in the following tables.    

Table 56 and Table 58 are based on the unconditioned failure rates in Table 25. Table 57 and Table 59 are based on the conditioned failure rates in Table 27. Table 56 (unconditioned) and Table 57 (conditioned) show the number of failures for one year in service. Table 58 (unconditioned) and Table 59 (conditioned) give the total number of failures over a 40 year service life.

#

1

2

3

4

Route length

km

65

65

65

65

Cable failures

#

0.09

0.17

0.26

0.35

Joint failures

#

0.18

0.35

0.53

0.70


#

0.00

0.01

0.01

0.01


#

0.27

0.53

0.80

1.06

Total number of Groups of Cables

Table 56 Unconditioned failure rates for a 65 km cable route length for one year in-service

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1

2

3

4

Route length

km

65

65

65

65

Cable failures

#

0.09

0.17

0.26

0.35

Joint failures

#

0.24

0.48

0.72

0.97


#

0.00

0.01

0.01

0.02


#

0.33

0.66

1.00

1.33


Table 57 Conditioned failure rates for a 65 km cable route length for one year in-service #


1

2

3

4

Route length

km

65

65

65

65

Cable failures

#

3.46

6.92

10.37

13.83

Joint failures

#

7.03

14.05

21.08

28.11


#

0.12

0.24

0.36

0.48


#

10.61

21.21

31.82

42.42

Table 58 Unconditioned failure rates for a 65 km cable route length for forty years in-service #

1

2

3

4

Route length

km

65

65

65

65

Cable failures

#

3.46

6.92

10.37

13.83

Joint failures

#

9.65

19.31

28.96

38.61


#

0.17

0.35

0.52

0.69


#

13.28

26.57

39.85

53.14


Table 59 Conditioned failure rates for a 65 km cable route length for forty years in-service

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15 500 kV STUDY PROJECT RISKS 15.1 Technical risks 15.1.1 Inability of the accessories to meet the required minimum winter design temperatures. The manufacturers are unable to convincingly demonstrate in a pre-bid or in technical prequalification exercises that their accessories have a good prospect of passing the low temperature proving tests. Preventative Actions: 

At the earliest opportunity and prior to drafting low temperature proving test requirements, gather information from other utilities and manufacturers on lower voltage XLPE cable systems with accessories operating under low ambient conditions.

Remedial Action:  At the pre-bid stage revise the system design parameters: o Install the cables at a greater depth in the direct buried and duct-manhole systems at a depth where the ground temperature is higher. This reduces the ampacity of each cable. For a significant increase in depth it will be necessary to add an additional cable per phase, increasing the number of groups of three single core cables from four to six for Scenarios 1 and 2. o Install the cables in a tunnel in which the minimum air temperature is limited to an acceptable level by the ventilation control system.  Select an SCFF cable system instead of an XLPE cable system. (The additional maintenance liabilities of, and the implications of possible fluid leakage from, an SCFF system would have to be accepted)

15.1.2 Uncertainty of the winter minimum design temperature Preventative Action  At the earliest opportunity obtain measurements by performing field trials and installing temperature measuring devices at various depths in representative positions.  Increase the design margin to be specified for the accessory performance. At present the design margins have been proposed at -10oC for a) the joints giving design temperatures of -15oC for direct burial, -20oC for duct-manhole, -10oC for the deep tunnel and -20oC for the shallow tunnel. At present the design temperature for the outdoor termination and associated cable has been set according to requirements for other items of plant at -50oC.

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Evaluate the feasibility of trace heating equipment.

15.1.3 Failure of the joints to demonstrate reliability in the Proving Tests Failure of the prefabricated designs of joints (OPJ or PJ types) to demonstrate reliability during Proving Tests for the 500 kV Study Project. (This is considered to be improbable as some manufacturers’ designs of OPJ and PJ joints are understood to have already completed type approval tests.) Preventative Actions:  

At the pre-bid stage examine in detail the status and relevance of any 500 kV 2,500 mm2 prequalification tests already performed and only accept bids from manufacturers with proven EHV, large conductor, test and service experience. Only accept bids from manufacturers with sufficient in-house development resources.

Remedial Actions: 

At the contract stage, the manufacturer must remedy the situation.

15.1.4 Failure of the cable system to achieve reliable service performance Failure of the cable and accessories supplied for the 500 kV Study Project to demonstrate a reliable consistency of service performance. (This likelihood can be reduced if suppliers ensure stringent quality control measures). Preventative Actions:  Specify, and ensure suppliers agree to, the following project specific requirements: o Special Proving Tests for low temperature operation. o Prequalification tests (These would typically be based on the requirements of IEC 62067[1], but can include additional requirements). o Type tests (These would typically be based on the requirements of IEC 62067[1], but can include additional requirements). o Routine tests (These would typically be based on the requirements of IEC 62067[1], but can include additional requirements). o Sample tests on cables and accessories, including tests, additional to the material and high voltage tests specified in IEC 62067[1], to demonstrate consistency of performance at low temperature (not covered by international procedures).

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o Quality control and remedial action procedures (not covered by international procedures) o Inspection and test plan (This is not fully covered by international procedures) o Full size accessory assembly trials (This is not fully covered by international procedures) o Jointer training programme, testing and approval for all jointers who will work on the 500 kV Study Project (This is not fully covered by international procedures). o Full size installation trials, where special to the 500 kV Study Project (not covered by international procedures). o Commissioning testing (This is partly covered by IEC 62067[1]) o Develop and document repair procedures, suitable for conditions where there could be induced voltages, for exposing failed cable or accessories, preparing the site environment and making a repair under simulated service conditions.         

Train the HPT project engineers for 500 kV cable systems in: Cable and accessory factory inspection and monitoring procedures. Installation inspection and monitoring procedures. Commissioning inspection and monitoring procedures. In-service routine monitoring, inspection and maintenance procedures. Repair inspection and maintenance procedures. Install four Groups of Cables to give full contingency. Purchase each group of three single phase cables from a separate manufacturer, to eliminate common mode failure. Add a performance penalty clause to the contract for an extended warranty period to require that the supplier has an engineer and jointers on site within, say, 48 hours of notification of failure.

Remedial Actions:  Switch to the load to the parallel circuit.  Replace all the suspect components supplied by the particular manufacturer.

15.1.5 Inability to repair the circuit at winter minimum ambient temperature: Preventative Actions:  Specify the repair requirement in the request for quotation.  Perform trials and establish procedures for cold weather repairs.  Install four Groups of Cables to give full contingency.  Purchase large tents and heater systems for cold weather use.

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Install cables in a tunnel: Store a short repair length of cable in the warm tunnel

Remedial Actions:  Switch the load to the parallel circuit.  Repair the circuit when the ambient temperature rises.

15.2 Contractual risks 15.2.1 Failure to attribute responsibility: In the event of project delays, inadequate quality control or failures where the cause is not clear, there can be difficulty in attributing the blame to the responsible party. Preventative actions:  For a high technology 500 kV cable system, a single contractor should be responsible on a turnkey basis for the complete project, including supply, jointing and installation.  Specify that the cable system suppliers’ technical recommendations and requirements must take priority over installation convenience. Remedial action: 

Investigate the cause of the problem, determine and take remedial action. Attribute or apportion blame accordingly in an attempt to recover costs.

15.3 Schedule risks 15.3.1 Delayed development: Preventative actions:  A period of twenty seven months has been allowed in total for all the development (thermal, mechanical and electrical) and formal witnessed prequalification and type approval work tests. This is considered to be reasonable.  At the earliest opportunity seek advice from the manufacturers.  Select a manufacturer with sufficient in-house development resources. Remedial Actions:  At the contract stage, the manufacturer must remedy the situation.

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15.3.2 Delayed manufacture: Preventative actions: 

      

Allow sufficient time within the project schedule for manufacture. (A period of approximately eighteen months has been anticipated for the manufacture of 120 km of single core cable as the range of manufacturing periods advised by prospective manufacturers was generally between one to two years. Whilst this is believed to be reasonable at this stage, the programme requires agreement with the manufacturers.) Engage multiple suppliers so as to reduce the impact of a delay by any one supplier. Engage sufficient suppliers to enable required quantity of cable to be manufactured within the required time frame. Check that the manufacturers have allowed for reasonable durations and contingencies in their programmes. Engage suitable expediter services. Impose conditions within the contract that penalise the supplier for late delivery. Ensure that agreed quality control and inspection and test plans are in place and are being observed. Perform frequent visits to supplier’s factories to ensure manufacture and testing is being performed correctly.

Remedial Actions:  At the contract stage, the manufacturer must remedy the situation.

15.3.3 Delayed installation and commissioning: Preventative Action:  Sufficient jointing teams need to be available for the number of joints to be installed.  Increase the span length of cable to 700 metres or more to reduce the number of joints and the jointing period.  Agree an achievable installation period including contingences with the cable supplier, civil installer and any other critical contractors.  Establish a buffer stock of cables and accessories. Remedial Actions:  At the contract stage, the critical suppliers and contractors must remedy the situation.

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15.3.4 Damage to cable during delivery or installation Preventative Action: 

               

Ensure that there are detailed specifications for a) the cable pulling eyes and despatch cap fitted in the factory are fully water and pressure tight, b) the reel and it’s battening, c) the reel transport cradle and d) the reel lifting eyes are sufficiently robust and stable to withstand without damage the shipping, lifting and road delivery activities. Specify that the temporary lay down areas for the reel are stable load bearing and level surfaces. Specify that the route to site be proven by performing a trial drive-through. Establish a buffer stock of reels. Position the joint bays to use equal section lengths of cable to allow maximum flexibility and contingency. Specify that a cable installation trial be performed, especially if specialised or nonstandard equipment is to be used and if the cable is to be installed in a special configuration. Specify that the cable installers have evidence of relevant experience with large diameter, heavy, long length EHV cables and that their references are validated. Specify that the pulling tensions be a) calculated for the particular span and that these are below the manufacturer’s limit for the cable and b) measured during the pull. Specify that jointers be present on site to immediately make the cable water tight should a pulling eye be pulled off or the metallic sheath damaged. Ensure that a type approved jacket repair technique together with materials is available. Perform an HV DC test on the jacket as soon as the cable is laid, locate the position of any damage, repair the jacket and re-test. Mark the cable phase colours and note the cable numbers on each of the cable ends in the joint bays and vaults before and after rolling them at the cross bonded transposition. Apply protection to the exposed cable ends in the joint bay or vault. Ensure that the full security measures are put in place until the trench is backfilled. Ensure that the trench base and/or duct bores are clean. Ensure that the blinding and backfill is free of sharp stones that could damage the cable. Ensure concrete cover tiles are not placed on the side of the trench when pulling-in cable.

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Select plastic cover tiles in preference to concrete cover tiles to reduce the risk of them being dropped and penetrating the cable through the blinding layer. Perform a repeat HV DC test on the cable jacket immediately after backfilling. Prevent site vehicles from driving over the filled trench or joint bay.

Ensure that all damage is reported to the supplier and is investigated immediately. If damage is proven to be confined to the jacket, apply a jacket repair and re-test. If damage to the cable insulation is suspected then remove and replace the span length.

15.3.5 Commissioning test failure and repair There is a risk with XLPE cable systems that a low incidence of failures of accessories will occur during the HV AC site commissioning tests. Preventative Action  Ensure that the cable is installed correctly and that factory serving tests have been performed on the jacket.  Specify that a full quality plan be in place for the preparation of the assembly area of the accessories (joint bay or joint vault). The quality plan should include full traceability of the cable numbers, joint numbers (together with key components numbers), jointing drawings, jointing instructions, critical assembly tool numbers, jointer and assistant jointer names, site engineer names and test engineer names. All staff must be trained and approved as competent.  Specify that the jointers must check the condition and key dimensions of the cable and of the accessory components and that any anomalies must be reported and investigated immediately.  Specify that a supplier’s competent and experienced senior design engineer is to be present on site during the assembly of the first accessories. Specify that a report of the findings and any recommended actions is to be produced and acted on before further accessories are assembled.  Ensure that at least two spare joints, one spare termination and sufficient spare cable are to be available on site together with a complete written assembly procedure, prior to commencing the commissioning tests. Specify that the supplier must be able to have appropriate Cable Jointers available for any repair works.  Ensure that equivalent commissioning tests and PD diagnostic tests have been performed on the cable system in the factory during development (e.g. on the prequalification tests installation or type test installation).  Ensure that a competent test engineer is to be in charge of the commissioning tests.

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  



Remedial Action   

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Specify the test requirements in full. Ensure that an agreed tests procedure and circuit diagram is available before the test commences. Specify that any a) PD diagnostic sensors and b) distributed temperature sensors, fitted permanently inside the accessories or inside the link boxes must have been present during all of the prequalification and type approval tests and must be listed on the type approved drawings, parts lists and jointing instructions. Allow sufficient time, say three months, within the project schedule for the possibility that failures (typically of accessories) will occur during the HV AC site commissioning tests.

At the contract stage, the critical suppliers and contractors must remedy the situation. The presence of any partial discharge detected during the commissioning tests shall be investigated and shall be shown not to have emanated from within the cable system irrespective of the magnitude or type of partial discharge. Any failure of the cable or accessories is to be immediately reported and investigated by the supplier, who is to advise remedial actions supported by a full technical justification.

15.4 Common mode failure 15.4.1 Repeated latent defect in manufactured cable or accessories Preventative Actions   

As for 15.1.4. Require the suppliers to provide extended warranties to cover Latent Defects in manufacture. Engage a different manufacturer to supply each parallel Group of Cables

Remedial Actions   

During the warranty period the supplier must remedy the situation. Identify cause of failures. From the quality records identify all suspect joints or cable and monitor, repair or replace.  After warranty period engage the supplier or another manufacturer: o For latent defect in cable: to replace all suspect cable spans and associated accessories.

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o For latent defect in joints: to replace all suspect joints with two joints and a short length of cable

15.4.2 Repeated jointing error Preventative Actions  

As for 15.3.5 Engage a different manufacturer, using different jointers, to supply each parallel Group of Cables.

Remedial Actions   

During the warranty period the supplier must remedy the situation. From the quality records identify all suspect joints and monitor, repair or replace. After warranty period engage the supplier or another manufacturer to replace all suspect joints with two joints and a short length of cable

15.4.3 Third party damage. Preventative actions               

Install each buried group of three single phase cables in individual trenches, widely spaced apart. Enforce no dig zone over cable route Publicise ‘phone before you dig’ policy Install mechanical protection around buried cables Install cables at sufficient depth to avoid damage whilst other services are being worked upon Install cables at sufficient depth to avoid damage from agricultural machinery Install warning tapes and tiles above cables Install distinguishing coloured backfill or trench fill above cables Install marker posts above cable route Install robust barriers around ground level sheath bonding equipment Prepare detailed route records Regularly walk over and inspect the route. Install cables in a tunnel Hold spare joints and cable to minimise unavailability Install cable terminations where they will not be a target for malicious damage.

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Agree on a maintenance/repair agreement with the supplier.

Remedial Actions 

Repair all damaged cables with two joints, or one joint and a termination, and a length of cable

15.4.4 Fire in tunnel. Preventative actions          

Select XLPE cable in preference to SCFF cable Inhibit auto-reclose Install each circuit in a separate or segregated tunnel Install fire detection and fire extinguishing system. Specify reduced fire propagating cable jackets and robust metallic sheath Install fire barriers in tunnel to segregate the tunnel and limit the length of fire damage Install fire dampers to eliminate the oxygen supply in the event of a fire. Add intumescent3 coating to the cables Design to minimise the effects of failure. Minimise the use of materials with potentially hazardous by-products in the event of fire.


Repair tunnel structure. Replace all damaged cables, accessories, ancillaries and support structures

15.5 Collateral Damage 15.5.1 Failure of one cable causes damage to another Preventative actions 

Ensure cables are spaced and not touching

3

intumescent paint: a substance which swells as a result of heat exposure and provides a useful degree of fire protection to the polymeric cable jacket.

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Repair damaged cables and accessories

15.5.2 Failure of one joint causes damage to another Preventative actions  

Install joints direct in the ground and completely surround with backfill. Install blast proof screens between joints and adjacent cables in manholes or tunnels


Ensure manhole dimensions are suitable to accommodate two sets of repair joints

15.5.3 Failure of one termination causes damage to another Preventative actions   

Do not select porcelain insulators for air insulated cable terminations Specify that air insulated cable terminations should be designed to release internal pressure vertically and not horizontally Do not select of oil immersed cable terminations (i.e. direct cable connections into oil filled equipment such as transformers or reactors)



15.5.4 Testing of one cable system causes damage to another  

Following failure of a DC jacket test, prohibit the ‘burning out’ of faults by the application of continued current as this risks igniting the jacket and spreading fire to adjacent cables in ducts and tunnels Use visual inspection instead of DC voltage to check the integrity of cables jacket in tunnels.

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Limit the available energy that can be released in the event of a failure during HV AC testing by using a resonant test set and not connecting the circuit to the grid for testing



15.5.5 Repair of one cable causes damage to another Preventative actions    

Ensure cables are in horizontally flat spaced configuration in buried and duct systems Ensure cables in tunnels are in a configuration where all cables can be safely removed and replaced, generally this implies vertically flat spaced configuration. Prohibit the use of mechanical excavation immediately above cables or ducts. Excavate to the side and use hand tools thereafter. Use only approved and tested sand blasting or water jetting methods to exhume cables and accessories buried in cement bound sand



15.6 Cost risks Price variance: cable scheme  Increase in number of cables per phase from 2 to 3:  Crossing of obstacles requires a depth at which increased cable spacing is ineffective in limiting operating temperature to 90oC.  Detailed survey of winter ground temperatures shows need to install deeper  Trial holing reveals unfavourable thermal ground conditions  Trial holing reveals unrecorded major obstacles  Development tests show cable joints unable to operate reliably at -10oC in ground, requiring installation at greater depth. Price variance: cable  Copper price

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  

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Currency exchange rate Other material price fluctuations Optimistic price estimates

Price variance: civil  Labour rates  Material rates  Weather  Unfavourable ground type  Sphagnum moss/muskeg  Rock  Running sand  Waterlogged  Heavy clay  Unsuitable thermal properties  Unexpected obstruction  Optimistic price estimate

Authors: Unsigned: Electronic copy

Alan Williams

Brian Gregory

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16 DEFINITIONS AND GLOSSARY Listed below are definitions and descriptions of cable related terminology used in this report and elsewhere.

500 kV Study Project

The 500 kV underground cable system described and discussed in this feasibility study.

AC

Alternating Current. A current that flows alternately in one direction and then in the reverse direction. In North America, the standard for alternating current is 60 complete cycles each second. Such electricity is said to have a frequency of 60 hertz. Alternating current is used in power systems because it can be transmitted and distributed more economically than direct current.

Accessories

Parts of the cable system. Terminations that provide connections to other items of transmission plant or joints that connect lengths of cable. Cable Accessories are described in more detail in Section 3.4 of this report.

AEIC

Association of Edison Incorporated Companies. AEIC's members are electric utilities, generating companies, transmitting companies, and distributing companies from within and outside the United States. AEIC provides underground cable specifications.

AESO

Alberta Electric System Operator. AESO is an independent, not-for-profit transmission agency who plans and operates Alberta’s interconnected electric system.

AltaLink

AltaLink is a TFO that owns and operates transmission lines and substations. It is part of the HPT.

Amp

The unit of electric current; the full name is ampere.

Ampacity

The current in amperes a conductor can carry continuously under the conditions of use without exceeding its temperature rating. It is also known as current rating. Ampacity is measured in amps.

Ancillaries

Parts of the cable system. Equipment, other than cables and accessories, such as bonding equipment, used to complete a cable system. It includes equipment that is used to provide monitoring and maintenance facilities.

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Backfill

The materials of suitable thermal properties that are placed around and tamped over the underground cable and joints to restore the excavation to its final finish. The materials used immediately around the cables or ducts. It is also the act of placing and tamping these materials.

BEWAG

Die Burgenländische Elektrizitätswirtschafts-Aktiengesellschaft. The organisation responsible for the transmission of EHV electricity in Berlin.

BIL

Basic Insulation Impulse Level. The very short duration ‘lightning’ impulse voltage to which equipment must be tested.

Bonding

The electrical connection of the cable Sheath or Shield to earth (ground).

Bonding Cables

The insulated conductor forming the connection between the sheath or shield of the cable, joint or termination base-plate, and a link in the link box.

Cable Clamp

A device for restraining cables against movement; also referred to as a cleat.

Cable Joint

A cable accessory used for connecting lengths of cable together. Cable Accessories are described in more detail in Section 3.4 of this report.

Cable Jointer

The trained person who assembles cable joints on site. In North America commonly referred to as a Cable splicer (or journeyman).

Cable Loss

The total energy loss in the form of heat generated in the cable. The Cable Loss comprises Conductor loss, Dielectric loss and Sheath loss. It is measured in Watts per metre.

Cable Splice

Another expression for Cable Joint. Cable Accessories are described in more detail in Section 3.4 of this report.

Cable Splicer

Another expression for Cable Jointer.

Cable System

Cable complete with installed Accessories and Ancillaries which permits flow of power from one end of the circuit to the other.

Capacitance

That property of a system of conductors and dielectric, which permits the storage of electric Charge when there is a voltage between the conductors. Underground cable dielectrics have capacitance.

CBS

Cement Bound Sand. A material commonly used as a Backfill around cables.

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CCI

Cable Consulting International Limited.

Cct

Circuit.

CCTV

Closed Circuit Television.

CESI

CESI is a company located in Milan, Italy, that can test power system equipment including EHV cable.

Charge

The total amount of electricity that is a) stored in the insulation or b) flows in the conductor. Current is the rate of flow of Charge. The unit of Charge is a Coulomb.

Charging Current

The flow of electricity into and out of the cable dielectric. This current flows whenever the cable is energized with AC voltage in-service, whether or not it is carrying any useful power.

CIGRE

International Council on Large Electric Systems, an organisation in the field of high voltage electricity including cable systems. From time to time CIGRE publish results of surveys and recommendations for test methods.

Circuit

A conductor or a system of conductors through which electric current is intended to flow. In this study a 500 kV circuit is used to describe an electrical connection linking two pieces of Transmission Equipment. Whilst several groups of cables can link the same two pieces of Transmission Equipment, in order to qualify as separate circuits they must be capable of being switched in or out independently. A three phase AC circuit includes at least three conductors, one for each phase. More than one conductor for each of the three phases can be provided.

Cleat

Another word for cable clamp.

Close Cleated

A way of installing cables in air, whereby the cables are restrained against lateral and longitudinal movement by locking the cable into position with cleats located at a comparatively short spacing.

Conductor

A material used for the transmission of electrical current and energy.

Conductor Loss

The energy loss in the form of heat generated in the conductor as a result of the flow of current. It is measured in Watts per metre.

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Conduit

Duct

Current

The flow of electric Charge in a conductor. Current is the rate of flow of Charge. Current is measured in amps.

Current Rating

Similar to ampacity.

CV

Continuous Vulcanising. The process used for cross linking an extruded XLPE insulated cable cores.

DC

Direct Current

DESS

Downtown Edmonton Supply and Substation. A 240 kV circuit in Edmonton utilising three 240 kV XLPE insulated underground cables.

Dielectric

The insulating material in a cable that separates the conductor from the outer protective covering. Dielectrics are non-metallic. Also known as insulation.

Dielectric Loss

The energy loss within the dielectric of a cable. This loss occurs whenever the cable is energized on voltage, whether or not it is carrying any useful power.

Direct Buried

A method of installing cables in the ground whereby the cables are intimately surrounded by, and are in contact with, the backfill. It is often called “laid direct”.

Direct Current

Current that flows continuously in the same direction, as opposed to alternating current. The current supplied from a battery is direct current.

Dissipation Factor

The tangent of the Dielectric Loss Angle, δ. It is often called tan δ. A measure of the energy loss characteristics of a dielectric material. A low Dissipation factor Dielectric exhibits low energy loss.

DTS

Distributed Temperature Sensing. A system using optical fibres to measure the temperature at a range of positions. Typically used to measure the temperature of the outside surface of the cable, or the air temperature within tunnels.

Duct

A conduit or tube designed or used for the accommodation of a cable or wire underground.

Duct Bank

A number of ducts combined in a group. In this report duct banks are typically buried in the ground encased in concrete or Fluidized Thermal Backfill (FTB).

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Duct-manhole system

A method of cable installation whereby each single core cable is installed in a separate pre-installed duct and is joined together in manholes (or vaults).

EHV

Extra High Voltage.

ELECTRA

The Journal published by CIGRE.

EMJ

Extrusion Moulded Joint. This is described more fully in Section 4.5 of this report.

EPCOR

EPCOR is a TFO that owns and operates electricity distribution & transmission and water and wastewater facilities in Alberta. It is part of the HPT.

EPDM

Ethylene Propylene Diene Monomer. A type of EPR modified to facilitate sulphur cross linking. Sometimes used for cable accessory insulation with dicumyl peroxide cross linking.

EPR

Ethylene-Propylene Rubber. A synthetic rubber used for cable accessory insulation, also used for HV cable insulation.

EPRI

Electric Power Research Institute. EPRI is an independent, non-profit company performing research, development and design in the electricity sector.

EQ

Extension to prequalification test. A long term test, described in CIGRE TB 303, performed in lieu of a prequalification test, in cases where a substantial change had not been made. EQ testing is described in more detail in Section 3.13.1.2 of this report.

Extra High Voltage

In this report Extra High Voltage cables are those with a nominal system voltage equal to or greater than 215 kV.

FRE

Fibre Reinforced Epoxy. FRE duct is a type of duct that can be used for cable duct bank construction.

Frequency

The number of cycles through which an alternating current passes in a second. The North American standard is 60 cycles per second, known as 60 Hertz.

FTB

Fluidized Thermal Backfill is a backfill with a guaranteed maximum thermal resistivity. It is installed as a slurry which later sets. It consists of aggregate, sand, a small amount of cement, water and a fluidizing agent.

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GIL

Gas Insulated Line. GIL can sometimes be used as an alternative to cable. It uses compressed gas as the insulator around the phase conductor. It is described in more detail in Section 4.10 of this report.

GIS

Gas Insulated/Immersed Substation/Switchgear. GIS is sometimes used in HV and EHV substations.

Group of Cables

In this report a Group of Cables is used to describe three single core cables, one for each phase. In this report one group of three single phase cables would typically be installed in one trench or ductbank.

GWP

Global Warming Potential. A method of comparing the global warming effect of a gas to that of carbon dioxide. The reference GWP of carbon dioxide is one.

HDD

Horizontal Directional Drill. A method of crossing below obstructions. A hole is drilled using a flexible guided drill similar to that used in the oil industry. Larger diameter reamers are then pulled back through the hole until it is large enough to pull in a duct or pipe, into which a cable can be installed.

HDPE

High Density Polyethylene. A type of plastic commonly used for cable jackets.

Heartland Transmission Project

Heartland Transmission Project involves the construction of a two high voltage transmission lines, which will connect the Heartland region (northeast of Fort Saskatchewan) to existing transmission facilities either west of Edmonton or south of Edmonton.

High Voltage

In this report High Voltage cables are those with a nominal voltage above 36 kV but less than 215 kV.

HPT

Heartland Project Team. The Project team comprise AltaLink and EPCOR.

HTS cable

High Temperature Superconducting Cable. Further details of HTS cable are given in Section 4.11.

HV

High Voltage.

Hz

Hertz. The unit of frequency for alternating current. Formerly called cycles per second. The standard frequency for power supply in North America is 60 Hz.

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ICEA

Insulated Cable Engineers Association. ICEA is an organization that develops cable standards for the electric power, control, and telecommunications industries. ICEA is a "Not-For-Profit" association whose members are sponsored by over thirty of North America's cable manufacturers.

ID

Internal Diameter.

IEC

International Electrotechnical Commission. The IEC prepares and publishes International Standards for all electrical, electronic and related technologies.

IEEE

Institute of Electrical & Electronics Engineers, Inc. IEEE is a professional association based in the United States that issues publications and technology standards.

Induced Voltage

Induced voltages are the voltages which can be induced in power cables and associated auxiliary cables and other parallel metalwork, due to their proximity to cables, overhead lines or to natural phenomena.

Insulation

Insulation is a material that resists the flow of electric current. The insulation of an AC cable is also called the dielectric.

IPCC

Intergovernmental Panel on Climate Change

IREQ

The Institut de Recherche d'Hydro-Québec (Hydro-Québec's Research Institute).

Jacket

The outer extruded polymeric layer of a cable. Cable components are described in more detail in Section 3 of this report.

Joint

See Cable Joint

Joint Bay

A temporary underground chamber used during assembly of the cable joints. With a direct buried system the joint bays are fully backfilled before the cable system is put into service.

K.m/W

Degrees Kelvin metres per Watt. A unit of thermal resistivity.

kcmils

Thousands of circular mils. A circular mil is a unit of area, equal to the area of a circle with a diameter of one mil. A mil is one thousandth of an inch.

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kg/m

Kilograms per metre. A unit of mass per unit length. Often used to describe the weight of a cable.

kV

Kilovolt equals 1000 volts.

kW

Kilowatt. 1 kilowatt equals 1000 Watts. The unit of real, or useful, electrical power. Power is the rate of delivery of electrical energy.

LDPE

Low Density Polyethylene. A type of plastic used as the base material for XLPE cable insulation.

Latent Defect

In this report a Latent Defect is a defect in design, material, product and/or workmanship which may cause failure or malfunction at a later date, but which is not discovered during qualification tests or normal production or installation inspection or tests.

Link box

A box through which cable sheath bonding and/or grounding connections are made. The box contains removable links and may also contain sheath voltage limiters.

Link Pillar

Similar to a link box, but installed above ground.

LPP

Laminated Polypropylene Paper. A type of insulating tape which contains Polypropylene used in SCFF cables. It is described in more detail in Section 4.2 of this report.

LSZH

Low Smoke Zero Halogen. A type of fire performance material commonly used for cable jackets when the protection of people, buildings and equipment from toxic and corrosive gasses is critical.

mA/m

Milliamps per metre. A unit of current per unit length. It is commonly used for charging current in cable dielectric.

Manhole

An accessible underground chamber in which the cable joints are located. It is not backfilled when the cable is in-service. It is also called a vault.

MDPE

Medium Density Polyethylene. A type of plastic commonly used for cable jackets.

Min

Minimum.

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mm²

Square millimetres. A unit of area. Commonly used to describe the cross sectional area of cable conductors.

Mutual Heating

The temperature rise on one cable due to the head generation by the adjacent cables (or any other sources of heat).

MV/m

Megavolts per metre. A unit of electrical field strength or stress used in the design of cable insulation. One Megavolt equals 1,000,000 volts.

MVA

Millions of Volt-amps. A unit of apparent power. The apparent power transmitted along a cable system may exceed the real power.

MW

Megawatt. A unit of real, or useful, power; 1 MW equals 1000 kilowatts.

Net Present Value

A single number that expresses the stream of costs in terms of an equivalent lump sum paid today. Nominal Value.

nom Nominal Value

Value by which a quantity is designated. The nominal value is not necessarily identical to the actual value but is expected to be close to it.

NPV

Net Present Value

OD

Outside Diameter.

OHL

Overhead Line

OPJ

One piece joint. This is described in more detail in Section 4.5 of this report.

Oversheath

Another word for cable jacket.

P&T

Pilot and Telephone. A generic term to describe the additional cables that are commonly installed alongside power cables.

PD

Partial Discharge.

Partial Discharge

A spark within a small air or gas-filled void in the insulation.

PE

Polyethylene.

Polyethylene

A thermoplastic material that can be extruded.

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Poly Vinyl Chloride

A thermoplastic material that can be extruded.

PVC

Poly Vinyl Chloride.

pF/m

PicoFarads per metre. A unit of capacitance per unit length. It is commonly used for capacitance of a cable dielectric.

Phase

In this report, a phase is one of the three conductors or cables used for the transmission of high voltage AC electricity. Each phase of a circuit may comprise several conductors or cables.

PIB

Poly Iso Butene. One of the types of insulating liquid used to fill some types of cable Terminations.

PJ

Prefabricated Joint. This is described more fully in section 4.5.

Pothead

Anther word for cable termination.

PQ

Prequalification Tests.

Prequalification Tests

Prequalification Tests are long term (typically 1 year in duration) tests on cable systems. The test arrangement shall be representative of the installation design conditions. Requirements for Prequalification Tests are specified in IEC 62076[1]. AEIC CS9-06[10] also makes reference to Pre-Qualification tests which are similar in scope and purpose to those required by IEC 62076. Testing requirements for 500 kV cable systems are described in more detail in Section 3.13 of this report.

Private Tests

In this report, Private Tests are those instigated by and conducted on behalf of manufacturers in the course of their product development. Manufacturers may, or may not, wish to share the results of such tests with their clients.

Production Tests

Tests conducted on production cables or accessories at the factory. Production tests include non-destructive tests conducted on all shipping lengths and tests conducted at specified frequencies on representative samples of cables and accessories. Production tests are specified in standards and specifications published by ICEA and AEIC. Production Tests are described as Routine Tests and Sample Tests in IEC standards. Testing requirements for 500 kV cable systems are described in more detail in Section 3.13 of this report.

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Proving Tests

In this report, the term “Proving Tests” is taken to include any Prequalification Tests which are prescribed in published standards and specifications and specified by the client, plus any additional tests which the client requires to be satisfactorily passed before acceptance for service.

QC

Quality Control. The process by which the required level of product integrity and performance is monitored and achieved.

Qualification Test

Qualification Tests are intended to demonstrate the adequacy of designs supplied by a particular manufacturer. Qualification Tests are specified in standards and specifications published by ICEA and AEIC. Qualification Tests are described as Type Tests in IEC Standards. Testing requirements for 500 kV cable systems are described in more detail in Section 3.13 of this report.

Rated Voltage

The nominal phase to phase operating voltage of the transmission system.

Reactor

A Reactor is an item of electrical equipment that can be used to partially compensate for the adverse electrical effect of the Capacitance in a long cable route.

Reel

Cables are stored and transported from the manufacturers works to the installation site on cable reels. These are also sometimes referred to as cable drums.

Relative Permittivity

An electrical property of the cable dielectric indicative of its ability to store Charge. Relative permittivity is given the symbol ε. It is used in the calculation of capacitance and dielectric loss.

Resistance

The opposition to current flow. Resistance is measured in ohms.

Right of Way

A strip of land reserved for public roads, railway tracks, pipelines, supply lines, communication lines, or other services.

Route Length

In this report the Route Length of the cable is used to describe the distance along the route between the cable terminations. It is also used to describe the total route length of a circuit which can comprise both cable and overhead lines, in which case it is the distance between the substations at each end.

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Routine Tests

Tests made by the manufacturer on each manufactured component (length of cable or accessory) to check that the component meets the specified requirements. (IEC 62067[1]) Requirements for Type Tests are specified in standards published by IEC. Testing requirements for 500 kV cable systems are described in more detail in Section 3.13 of this report. These are also known as shipping tests.

Sample Tests

Tests made by the manufacturer on samples of complete cables or components taken from a complete cable or accessory, at a specified frequency, so as to verify that the finished product meets the specified requirements. (IEC 62067[1]) Requirements for Sample Tests are specified in standards published by IEC. Testing requirements for 500 kV cable systems are described in more detail in Section 3.13 of this report.

SCFF

Self Contained Fluid Filled. A type of HV U/G Cable. Detailed descriptions of SCFF cable systems are given in more detail in Section 4.2 of this report.

Screen

A conducting layer that bounds the inner and outer surface of the cable or Accessory Insulation. Also known as a Shield.

Screen Interruption An insulated gap within a joint or termination that insulates the screen on one side of the joint from that on the other side for the purpose of Special Bonding. Sealing Ends

Another expression for cable Terminations. Cable accessories are described in more detail in Section 3.4 of this report.

SF6

Sulfur Hexafluoride. An insulating gas used in GIS and GIB.

Sheath

The metallic layer surrounding the cable insulation. Cable sheaths are described in more detail in Section 3 of this report.

Sheath Loss

The energy loss in the form of heat generated in the sheath as a result of the flow of current. It is measured in Watts per metre.

Sheath Loss factor

The ratio of the losses in a cable sheath to those in the central conductor. It is used in the calculation of ampacity and effective resistance.

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Sheath Voltage Limiter

A device with a non-linear resistance. At low voltage the resistance is high; at high voltage the Resistance is low. The Sheath Voltage Limiter prevents damage to the cable system by reducing the magnitude of transient voltages that appear during circuit switching and lightning strikes, a) across the cable jacket and b) across the screen interruption in joints and terminations.

Shield

A conducting layer that bounds the inner and outer surface of the cable Insulation. Also known as a Screen. The word Shield is also used for the integral ground return conductor within some cable constructions.

Silicone Oil

One of the types of insulating liquid used to fill some types of cable Terminations.

Span

In this report a span is a length of cable between adjacent joints (or a termination and the nearest joint). A span is sometimes also referred to as a cable ‘section’ or reel length.

Special Bonding

The type of sheath or shield bonding in which the flow of circulating current and generation of unwanted heat is prevented.

Splice

See Cable Splice.

Stage

In this report a stage refers to a part completion of the complete cable system. Typically the final system might be commissioned in several stages, with the total transmission capability only being available after completion of the final stage.

Stress

Electric field strength. Stress is an important factor in the design and performance of cable systems.

Substation

In this report a Substation is a fenced compound at which the circuit starts and ends. Other items of electrical equipment may also be located in the compound.

SVL

Sheath Voltage Limiter.

Swathe

In this report a Swathe is the temporary land width used for construction of an underground cable system. It would typically be bounded by fences during the construction period.

Tan δ

The tangent of the dielectric loss angle. It is often called the Dissipation Factor.

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TAT

Type Approval Tests. Equivalent to Type Tests.

TB

Technical Brochure. A document published by CIGRE.

TDR

Time Dependent Reflectometry. TDR is used in the analysis of a conductor (wire, cable, or fiber optic) by sending a pulsed signal into the conductor, and then examining the reflection of that pulse.

Termination

In this report the expression “Cable Termination” is used to describe the accessories on each end of the cable systems. Cable Accessories are described in more detail in Section 3.4 of this report.

TFO

Transmission Facility Owners.

Thermal Resistivity

The property of a material to oppose heat flow. Thermal Resistivity is measured in K.m/W.

Transition Station

In this report a Transition Station is a fenced compound at which an overhead line is connected to an underground cable. Other items of electrical equipment may also be located in the compound.

Transmission

The process of transporting electric energy in bulk on high voltage lines from the generating facility to the local distribution facility for delivery to retail customers.

TSB

Thermally Stabilised Backfill. Backfill material that has a guaranteed maximum value of thermal resistivity irrespective of moisture content or temperature.

Type Tests

Type Tests are intended to demonstrate the adequacy of designs supplied by a particular manufacturer. Requirements for Type Tests are specified in standards published by IEC. Testing requirements for 500 kV cable systems are described in more detail in Section 3.13 of this report. They are also known as qualification tests.

U

U is the abbreviation given in IEC standards to the rated power frequency system voltage between conductors for which the cable is designed.

Uo

Uo is the abbreviation given in IEC standards to the rated power frequency voltage between conductor and earth or metallic shield for which the cable is designed.

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Um

Um is the abbreviation given in IEC standards to is the maximum value of the "highest system voltage'' for which the equipment may be used.

V

V is the abbreviation given in ICEA and AEIC standards and specifications to the nominal phase-to-phase operating voltage of the system. It is equivalent to U in IEC standards.

Vault

A Manhole in which cable joints are located.

Vg

Vg is the abbreviation given in ICEA and AEIC standards and specifications to the nominal phase to ground operating voltage. It is equivalent to Uo in IEC standards.

Vm

Vm is the abbreviation given in ICEA and AEIC standards and specifications to the maximum continuous phase-to-phase system operating voltage. It is equivalent to Um in IEC standards.

Void

A cavity in the cable or accessory insulation, either within solid or liquid insulation, or at the interface with another insulating layer or screen.

Volt

A volt is a unit of potential difference measured between two points. Potential difference is the electrical force that drives the flow of electrical charge along a conductor (current).

Vt

Vt is the abbreviation given in ICEA and AEIC standards and specifications to the phase-to-ground test voltage.

W

Watts. A Watt is a unit of power.

Water Tree

A defect in XLPE insulation which is initiated by moisture and an electric field.

W/m

Watts per metre. A unit of power per unit length. It is commonly used for power losses from a cable.

XLPE

Cross Linked Polyethylene. A type of insulation used in underground cables.

ε

Relative permittivity.

µΩ/m

MicroOhms per metre. A unit of electrical Resistance per unit length. It is commonly used for resistance of a conductor or cable.

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FEASIBILITY STUDY REFERENCES 1

IEC 62067 Edition 1.1 2006, ‘Power Cables with Extruded Insulation and their Accessories for Rated Voltages above 150 kV (Um = 170 kV) up to 500 kV (Um = 550 kV) – Test Methods and Requirements. 2 Cao X, Liu Y, Fang H and Gong Z, ‘500 kV Power Supply Cable Project for City Central Zone of Shanghai’, Paper B1-106, CIGRE Conference, 2008, Paris. 3 Parpal JL et al, 'Prequalification Testing of 345kV Extruded Insulation Cable System', Paper 21-101, CIGRE Conference 1998, Paris. 4 Parpal JL et al, 'Prequalification Testing of 290/525 (525) kV Extruded Cable System at IREQ', Paper A2.3, Jicable Conference 1999, Versailles. 5 Williams DE, ‘Natural and Forced Cooling of HV Underground Cables: UK practice’, pp137 – 161, IEE PROC, Vol 129 Pt. A. No 3 May 1982. 6 IEEE 404-2006, ‘Standard for Extruded and Laminated Dielectric Shielded Cable Joints Rated 2,500 V to 500,000 V’, Institute of Electrical and Electronics Engineers, March 2007, ISBN: 0738152943. 7 IEEE 48-2009, ‘Standard for Test Procedures and Requirements for Alternating Current Cable Terminations Used on Shielded Cables Having Laminated Insulation Rated 2.5 kV through 765 kV or Extruded Insulation Rated 2.5 kV through 500 kV’, Institute of Electrical and Electronics Engineers, August 2009. 8 ICEA S-108-720-2004, ‘Standard for Extruded Insulation Power Cables Rated above 46 through 345 kV’. 9 AEIC CS2-97 (6th Edition), ‘Specification for Impregnated Paper and Laminated Paper Polypropylene Insulated Cable, High Pressure Pipe Type’, March 1997. 10 AEIC CS9-06 (1st Edition), ‘Specification for Extruded Insulation Power Cables and Their Accessories Rated Above 46kV through 345 kV ac’, 2006. 11 IEC 60840 ed 3.0, ‘Power Cables with Extruded Insulation and their Accessories for Rated Voltages above 30 kV (Um = 36 kV) up to 150 kV (Um = 170 kV) - Test methods and requirements’, April 2004. 12 Arkell C.A, Blake W.E, Brealey A.D.R, Hacke K.J.H and Hance, G.E.A, ‘Design and Construction of the 400 kV Cable System for the Severn Tunnel’, Vol 124, No 3, Proceedings IEE, London. 13 Ray J.J, Arkell C.A, and Flack H.W, ‘525 kV Self-Contained Oil-Filled Cable Systems for Grand Coulee Third Power Plant – Design and Development’, Paper T73, IEE, 1973, London. 14 Ray J.J, Arkell C.A and Flack H.W, ‘525 kV Self-Contained Oil-Filled Cable Systems for Grand Coulee Third Power Plant – Design and Development’, IEEE Trans. PAS-93, 1974. 15 Arkell C.A, Johnson D.F and Ray J.J, ‘525 kV Self-Contained Oil-Filled Cable Systems for Grand Coulee Third Power Plant – Design Proving Tests’, IEEE Trans. PAS-93, 1974. 16 Rosevear R. D and Vecelli B, ‘Cables for 750/1100 kV Transmission’, 2nd IEE International Conference on Power Cables for 220 kV and Above, 1979, London.

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17

Foxall R.G, Bjorlow-Larsen K and Bazzi G, ‘Design, Manufacturing and Installation of a 525 kV Alternating Current Submarine Cable Link from Mainland Canada to Vancouver Island’, Paper 21-04, CIGRE Conference, 1984, Paris. 18 Cherukupalli S, MacPhail G.A, Nelson R.E, Jue J.S and Gurney J.H, ‘Application of Distributed Fibre Optic Temperature Sensing on BC Hydro’s 525 kV Submarine Cable System’, Paper B1-203, CIGRE Conference, 2006, Paris. 19 Minemura S, et al, ‘Completion of Installation of 500 kV PPLP-insulated Self-contained Oil Filled Cable Along Seto Ohashi Bridge for Honshu-Shikoku Interconnecting Transmission Line’, Sumitomo Electric Technical Review, 29, 1990. 20 ‘EPRI Underground Transmission Systems Reference Book’, Chapter 4, ‘Cable Construction: Extruded Dielectrics’, 2006 Edition, EPRI, Palo Alto, CA:2007.1014840. 21 Toya A, Kobashi K, Okuyama Y, Sakuma S, Katakai S and Kato K, ‘Higher-stress Designed XLPE Insulated Cable in Japan’, Paper B1-111, CIGRE Conference, 2004, Paris. 22 ‘EPRI Underground Transmission Systems Reference Book’, Chapter 8, ‘Cable Systems Accessories’, 2006 Edition, EPRI, Palo Alto, CA:2007.1014840. 23 Attwood J.R, Gregory B, Dickinson M, Hampton R.N and Svoma R, ‘Development of High Stress HV and EHV XLPE Cable Systems’, Paper 21-08, CIGRE Conference 1998, Paris. 24 Andersen P, et al, ‘Development of a 420 kV XLPE Cable System for the Metropolitan Power Project in Copenhagen’, Paper 21-201, CIGRE Conference 1996, Paris. 25 Helling K, Henningsen C.H, Polster K and Schroth R.G, ‘Power Supply for the City of Berlin: Are 380 kV XLPE Cables a Safe Alternative to Long-Time Proved LPOF-Cables?’, Paper 21-106, CIGRE Conference, 1994, Paris. 26 Henningsen C.H, Muller, K.B, Polster K and Schroth R.G, ‘New 400 kV XLPE Long Distance Cable Systems, Their First Applications for the Power Supply of Berlin’, Paper 21-109, CIGRE Conference, 1998, Paris. 27 Kaminaga K, et al, ‘Long Term Test of 500 kV XLPE Cables and Accessories’, Paper 21-202, CIGRE Conference 1996, Paris. 28 Ohata K, et al, ‘Construction of Long Distance 500 kV XLPE Cable Line’, Paper 31-36, Jicable 1999, Versailles. 29 Ohne H, et al, ‘Construction of the World’s First Long-Distance 500 kV XLPE Cable Line’, Paper 21-106, CIGRE Conference, 2000, Paris. 30 Granadinor R, Portillo M, Planas J and Schell F, ‘Undergrounding the First 400kV Transmission Line in Spain Using 2500mm2 XLPE Cables in a Ventilated Tunnel: The Madrid Barajas Airport Project’, Paper A.1.2, Jicable Conference, 2003, Versailles. 31 Miller D, ‘London Infrastructure Project’, CIGRE Electra 206, PP 24-35, February 2002. 32 S Sadler, S Sutton, H Memmer and J Kaumanns, ‘1600 MVA Electrical Power Transmission with an EHV XLPE Cable System in the Underground of London’, Paper B1-108, CIGRE Conference, 2004, Paris. 33 S. Sutton. R Plath and G Schroder, ‘The St. Johns Wood-Elstree Experience- Testing a 20 km long 400 kV XLPE-Insulated Cable System After Installation’, Paper A2.2, Jicable Conference, 2007 Versailles.

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Bjorlow-Larsen K, Del Brenna M, Kaumanns J, Meier R, Kirchner M and Argaut P, ‘‘Large Projects of EHV Underground Cable Systems’, Paper A.25, Jicable Conference, 2003. 35 Argaut P, Bjorlow-Larsen K, Zaccone E, Gustafsson A, Schell F, Waschk W, ‘Large Projects of EHV Underground Cable Systems’, Paper A.2.1, Jicable Conference, 2007. 36 Smith C, Galloway S, Gregory B, Lloyd S and Notman D, ‘The Development of an Ultrasound Quality Monitoring Process for the Manufacture of Enhanced Reliability HV and EHV XLPE Cables’, Paper A.2.6, Jicable Conference, 2003, Versailles. 37 Fudamoto K, Watanabe Y, Kish K, Uozumi T and Terayama A, ‘Development of One-Piece Type Joint (Self pressurized Joint) for 400 kV XLPE Cable’, Paper A.1.3, Jicable Conference, 2007, Versailles. 38 Kuwaki, A, Hayashi K, Kato, K and Imai N, ‘Development of 400 kV XLPE Cable and Accessories’, Paper A.1.1, Jicable Conference, 2007, Versailles. 39 Kobashi K, Ban S, Kanaoka M, Yonemura T and Ninobe H, ‘Completion of Prefabricated Joint for 500 kV XLPE Cable’, Paper A.5.4, Jicable Conference, 2003, Versailles. 40 CIGRE Technical Brochure 338, ‘Statistics of Underground Cables in Power Networks’, Working Group B1.07, December 2007. 41 ‘EPRI Underground Transmission Systems Reference Book: 2006 Edition’, EPRI Palo Alto, CA:2007. 1014840. 42 Khajavi M.B, and Zenger W, ‘Design and Commissioning Test of a 230-kV Cross-linked Polyethylene Insulated Cable System’, Paper A.1.1, Jicable Conference, 2003, Versailles. 43 Mikkelsen S.D and Argaut P, ‘New 400 kV Underground Cable System Project in Jutland (Denmark)’, Paper A.4.3, Jicable Conference, 2003, Versailles. 44 Jensen C and Argaut P, ‘400 kV Underground Cables in Rural Areas’, Paper B1-211, CIGRE Conference, 2006, Paris. 45 Rendina R, Posati A, Rebolini, Bruno G, Bocchi F, Marelli M and Orini A, ‘The New Turbigo-Rho 380 kV Transmission Line: An Example of the Use of Underground XLPE Cables in a Meshed Transmission Grid’, Paper B1-302, CIGRE Conference, 2006, Paris. 46 Vavre J and Wanda M, ‘400 kV Vienna -The Vienna 400 kV North Input’, Paper B1-101, CIGRE Conference, 2006, Paris. 47 Matallana J, Gahungu F, Duvivier M, Dubois, D and Mirebeau P, ‘400 kV 2500 mm2 XLPE Cable System Prequalification and Type Test for Middle East Environment’, Paper A.1.6, Jicable Conference, 2007, Versailles. 48 Koreman C.G.A, Aanhaanen G.L.P, Van Rossum J.C.M, Koning R.F.F, Boone W and De Wild F.H, ‘Development of a New 380 kV Double Circuit XLPE Insulated Cable System in the Netherlands’, Paper B1-107, CIGRE Conference, 2006, Paris. 49 CIGRE Technical Brochure 379, ‘Update of Service Experience of HV Underground and Submarine Cable Systems’, Working Group B1.10, April 2009. 50 Electra 151, ‘Recommendations for Electrical Tests – Prequalification and Development on Extruded Cables and Accessories at Voltages of Greater than 150 kV and Less than Equal to 400 kV’, CIGRE WG 21.03, December 1993.

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CIGRE Technical Brochure 303, ‘Revision of Qualification Procedures for HV and EHV AC Extruded Underground Cable Systems’, Working Group B1.06, August 2006. 52 Bolsa A et al, 'Prequalification Test Experience on EHV XLPE Cable Systems', Paper 21-104, CIGRE Conference, 2002, Paris. 53 Technical Brochure 218, ‘Gas Insulated Transmission Lines (GIL)’, CIGRE Joint Working Group 23/21/33.15, February 2003. 54 ‘EPRI Underground Transmission Systems Reference Book’, Chapter 7, ‘Cable Constructions: Special Applications’, 2006 Edition, EPRI, Palo Alto, CA:2007.1014840. 55 Feldmann D et al, ‘Development of a Directly Buried 400 kV Gas Insulated Line Technology’, Paper 21/23/33-02, CIGRE Conference 2000, Paris. 56 Nojima T et al, ‘Installation of 275 kV- 3.3 km Gas-insulated Transmission Line for Underground Large Capacity Transmission in Japan’, Paper 21/23/33-01, CIGRE Conference 1998. 57 J M Delcoustal, ‘A Very large GIL Project: PP9’, IEEE PES Summer Meeting Panel Session on GIL, July 1997, Berlin. 58 J Alter et al, ‘N2/SF6 Gas-Insulated Line of a New GIL Generation in Service’, paper 21-204, CIGRE Conference, 2002, Paris. 59 V. Piputvat et al, ‘550 kV Gas-Insulated Transmission Line for High Power Rating in Thailand’, Paper B1-107, CIGRE Conference, 2004, Paris. 60 P. Coventry et al, ‘New Generation of GIL Characteristics and Applications’, Paper B1-103, CIGRE Conference, 2004, Paris. 61 D Kunze et al, ‘Gas-Insulated Transmission Lines – Underground Power Transmission Achieving a Maximum of Operating Safety and Reliability’, Paper A 3.6, 2007 Jicable Conference, Versailles 62 M. Tinkham, ‘Introduction to Superconductivity’, unabridged republication of Second Edition, 1997, by Dover 2004, ISBN 0-486-43503-2. 63 BICC Cables, ‘Electric Cables Handbook’, Third Edition, Chapter 44, ‘Introduction to Superconductivity’, Chapter 45, ‘High Temperature Superconductors’ and Chapter 46, ‘High Temperature Superconducting Power Cables’, Blackwell Science, 0-632-04075-0. 64 Technical Brochure 229, ‘High temperature Superconducting (HTS) Cable Systems’, CIGRE Working Group 21.20, June 2003. 65 A Geschiere et al, ‘Optimizing Cable Layout for Long Length High Temperature Superconducting Cable System’, Paper B1-307, CIGRE Conference, 2008, Paris. 66 A Geschiere et al, ‘Installing a Long Distance HTS Cable’, Paper A 3.3, 2007, Jicable Conference, Versailles. 67 S Norman et al, ‘Design and Development of Cold-Dielectric (CD) High-temperature Superconducting Cable System for Bulk Power Transmission at Voltages up to 225 kV’, Paper 21-205, CIGRE Conference 2000, Paris. 68 M Nassi et al, ‘Design Development and Testing of the First Factory Made High Temperature Superconducting Cable for 115 kV – 400 MVA’, Paper 21-202, CIGRE Conference 1998, Paris. 69 J Ostergaard and O Tonnesen, ‘Design, Installation and Operation of World’s First High Temperature Superconducting Power Cable in a Utility Power Network’, Paper 21-205, CIGRE Technical Conference 2002, Paris.

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S. Honjo et al, ‘Verification Tests of a 66 kV High-TC Superconducting Cable System for Practical Use’, Paper 21-202, CIGRE Technical Conference, 2002, Paris. 71 M. Ichikawa et al, ‘Demonstration and Verification Test Results of 500-m HTS Power Cable’, Paper B1-104, CIGRE Conference, 2006, Paris. 72 S.I. Jeon, et al, ‘Development of Superconducting Cable System for Bulk Power Delivery’, Paper B1-06, CIGRE Conference, 2006, Paris. 73 HM Jang et al, ‘Type Test Results for 22.9 kV 50 MVA HTS Cable System in Korea’, Paper B1108, CIGRE Technical Conference, 2008, Paris. 74 D Lindsay et al, ‘Installation and Commissioning of TRIAX HTS Cable’, paper A.3.2, Jicable 2007 Conference, Versailles. 75 D Lindsay et al, ‘Operating Experience of 13.2 kV Superconducting Cable System at AEP Bixby Station’, Paper B1-107, CIGRE Conference, 2008, Paris. 76 J-M Saugrain et al, ‘Superconducting Cables – Status and Applications’, Paper A 3.1, Jicable 2007 Conference, Versailles. 77 F Schmidt et al, ‘Development and Demonstration of a Long Length Transmission Voltage Cold Dielectric Superconducting Cable to Operate in the Long Island Power Authority’, Paper A.3.4. 2007 Jicable Conference, Versailles. 78 Argaut P, Bjorlow-Larsen K, Zaccone E, Gustafsson A, Schell F, Waschk W, ‘Large Projects of EHV Underground Cable Systems’, Paper A.2.1, Jicable Conference, 2007. 79 Canadian Electricity Association. ‘Forced Outage Performance of Transmission Equipment 2007’. 80 IEC 60287-3-1: 1999. ‘Electric Cables – Calculation of the Current Rating – Part 3-1: Sections on Operating Conditions – Reference Operating Conditions and Selection of Cable Type’, Item 4.3. 81 ‘Appendix 608 – Technical Specification for the 240 kV Transmission Cable, Accessories and Installation, Supply and Install Transmission Cable and Accessories for the Downtown Edmonton, 240 kV Supply Line’. Item 8.3, page 10. 82 CEGB Design Memorandum 099/56, ‘Current Rating Requirements for Buried Cables, 132, 275 and 400 kV Systems, Section 10, November 1968. 83 IEC 60287--1: 2006. ‘Electric Cables – Calculation of the Current Rating – Part 1-1: Current rating equations (100 % load factor) and calculation of losses – General. 84 International Commission on Non-Ionizing Radiation Protection, ‘Guidelines for Limiting Exposure to Time-varying Electric, Magnetic, and Electromagnetic Fields (up to 300 GHz), (ICNIRP Guidelines)’ Health Physics, Volume 74, Number 4, April 1998.

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APPENDICES

1

Appendix: Overhead line performance and statistics

ALTALINK & EPCOR Heartland Underground: 500kV Overhead Line Forced Outage Performance Summary February, 2010

2

Appendix : Total capital cost estimate for each scenario

ALTALINK & EPCOR Summary: capital cost estimate for each scenario. List of itemised capital cost estimates for each scenario. February, 2010

3

Appendix : Economic comparison of scenarios for the 500 kV underground cable feasibility report

AESO Revenue requirement System energy loss Discount rate used in net present value calculations February, 2010

4

Appendix: Project schedule

500 kV Heartland Schedule October 2009

Distribution:

AESO, HPT, CCI Page 304 of 310

Cable Consulting International Ltd Registered in England and Wales No. 4234974 Registered office: 74 College Road, Maidstone, Kent, ME15 6SL, United Kingdom




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Appendix: System study (reactor requirements, voltage profiles and losses)

Teshmont ‘Underground Cable Project. Case Study for Underground Cable Sections on the 500 kV AC Lines Between Two Stations, Station A and Station B Heartland’ Technical Memorandum 2074-002-147-Rev11 2010 February 10 Study Report Sections: Executive Summary 1. Introduction 2. Shunt compensation 3. Study details (criteria and scenarios) 4. Network data 5. Results 6. Reactor requirements 7. Voltage profiles Appendix A: Evaluation of Losses on the 500 kV AC Lines Between Station A and Station B Appendix B: Case Study: Analysis of Scenarios without Shunt Compensation

6

Appendix: Generic crossings route maps: East TUC

ALTALINK & EPCOR ‘Heartland Underground Feasibility Study-East TUC’ Drawing (Aerial photograph) 1-16 Project No: 062235 November 16, 2009 Table of Crossing ID identification numbers and crossing facility types.

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Appendix: Generic crossings route maps: West TUC

ALTALINK & EPCOR ‘Heartland Underground Feasibility Study-West TUC’ Drawing (Aerial photograph) 1-14 Project No: 062235 November 12, 2009 Table of Crossing ID identification numbers and crossing facility types.

8

Appendix: Transmission System Requirements

AESO Transmission System Requirements, Heartland Project, February 11, 2010

9

Appendix: Analysis of the minimum winter temperatures recorded on the 240kV DESS circuit in Edmonton in 2009

Cable Consulting International ER 391: Analysis of the minimum Winter Temperatures recorded on the 240kV DESS Circuit in Edmonton in 2009, 16th October 2009

10 Appendix: The Damage Prevention Process In Alberta The Damage Prevention Process In Alberta. Roles, Responsibilities And Expectations Of The Stakeholders In The Prevention Of Damage To Buried Facilities Alberta Damage Prevention Council Alberta Chapter Canadian / American Public Works Association Issue No. 3, 05 September 2007

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11 Appendix: Potential overview of environmental effects of undergrounding Stantec ‘Overview of Potential Environmental Effects of Underground Transmission Lines’ November 2009

12 Appendix: Cable reel transportation study of feasibility and costs SNC- Lavalin ‘Heartland 500 kV Underground Cable Project Transportation Study Report’ November 2009

13 Appendix: Magnetic fields for cable and overhead line ALTALINK & EPCOR 2 graphs: Heartland D/C 500 kV Low Reactance Tower (2 x 500 MVA) – Magnetic Fields Heartland Underground Cable - 500 kV & 500 MVA Magnetic Fields (Direct Burial) December 2009

14 AESO introduction letter for CCI AESO Letter of Introduction re: Underground Cable Feasibility study July 8, 2009

15 500kV Heartland inquiry Cable Consulting International CABLE SYSTEM INQUIRY 500 kV HEARTLAND TRANSMISSION PROJECT 13th August 2009

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16 Appendix: 500kV Heartland transmission project response template Cable Consulting International CABLE SYSTEM INQUIRY 500 kV HEARTLAND TRANSMISSION PROJECT 14th August 2009

17 Appendix : AIS transition station scope of work ALTALINK EPCOR AIS Transition Station: Revision 0 October 2009

18 Appendix: Heartland underground construction: construction overview ALTALINK & EPCOR Document: ‘Heartland Underground: Construction Overview’ November 2009

19 Appendix : Heartland underground line-civil estimate ALTALINK EPCOR Heartland Underground Line: Civil Estimate Revision 0 October 2009

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20 Appendix: ‘Heartland underground crossing requirements’ ALTALINK & EPCOR Document: ‘Heartland Underground Crossing Requirements’ November 2009

21 Appendix : Heartland overhead line scope of work ALTALINK EPCOR Heartland Overhead Line: Bill of materials and assumed tower mix to connect substation 2 through a 500 kV double circuit link to substation 1. (No costs included). Revision 0 October 2009

22 Appendix : Substation 1 scope of work ALTALINK EPCOR Substation 1: Revision 0 October 2009

23 Appendix : Substation 2 scope of work ALTALINK EPCOR Substation 2: Revision 0 October 2009

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24 Appendix: Owners risk briefing ALTALINK & EPCOR Heartland Underground: Owners Risk Briefing October 2009

25 Appendix: Overhead and underground line maintenance ALTALINK & EPCOR Heartland Underground: Overhead and Underground line maintenance October 2009

26 Appendix: Drawings of termination stations, cable trenches, and obstruction crossings ALTALINK EPCOR 14 drawings prepared by SNC-Lavalin T & D List of drawings

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CCI Feasibility Study for 500 KV AC Underground Cables

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