United States

Department of

Agriculture

Rural

Utilities

Service

RUS Bulletin

1724E-300

Issued

June 2001

Design Guide for

Rural Substations
(BLANK PAGE)
UNITED STATES DEPARTMENT OF AGRICULTURE

Rural Utilities Service

RUS BULLETIN 1724E-300

SUBJECT: Design Guide for Rural Substations

TO: All RUS Borrowers

 RUS Electric Staff

EFFECTIVE DATE: Date of approval.

OFFICE OF PRIMARY INTEREST: Transmission Branch, Electric Staff Division.

INSTRUCTIONS: This bulletin is an update and revision of previous REA Bulletin 65-1, “Design

Guide for Rural Substations” (revised June 1978). Replace previous Bulletin 65-1 with this bulletin

and file with 7 CFR Part 1724.

AVAILABILITY: This bulletin is available on the Rural Utilities Service website at:

http://www.usda.gov/rus/electric

PURPOSE: This bulletin provides a basic design guide and a reference tool for designing rural

substations.

GENERAL: This Bulletin has been revised to bring the publication up to date with latest industry

standards, current RUS format, and technical requirements.

Our thanks to Cooperative Research Network of the National Rural Electric Cooperative Association,

(NRECA) which has supported this project, and it's consultant Burns & McDonnell Engineering

Company for the work which has made it possible to put this revision of the design guide together.

The following current and former members of the Substation Subcommittee of the (NRECA),

Transmission and Distribution (T&D) Engineering Committee provided invaluable assistance in

preparing this document.

1. Bardwell, Jim, SGS Witter, Inc., Albuquerque, New Mexico

2. Chapman, George, Patterson & Dewar Engineers, Inc., Decatur, Georgia

3. Eskandary, Mike, USDA-RUS-ESD-TB, Washington, DC

4. Howard, Jerrod, Central Electric Power Co-op, Inc., Columbia, SC

5. Kahanek, Bil, Lower Colorado River Authority, Austin, TX

6. Myers, Tom, Berkeley Electric Co-op, Moncks Corner, SC

7. Malone, Ken, Middle Tennessee EMC, Murfreesboro, TN

8. Nicholson, Norris, USDA-RUS-ESD-TB, Washington, DC

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TABLE OF CONTENTS

ABBREVIATIONS AND ACRONYMS.......................................................................................... 31

CHAPTER 1 - INTRODUCTION.................................................................................................... 37

1.1 PREFACE........................................................................................................................ 37

1.2 PURPOSE AND SCOPE................................................................................................. 37

1.3 RELATIONSHIP OF SUBSTATION TO OVERALL POWER SYSTEM......................... 37

1.4 IMPORTANCE OF ADEQUATE SUBSTATION PLANNING AND

ENGINEERING............................................................................................................... 38

1.5 TYPES OF SUBSTATIONS............................................................................................. 38

1.5.1 General.............................................................................................................. 38

1.5.2 Distribution Substations ....................................................................................... 39

1.5.3 Transmission Substations..................................................................................... 39

1.5.4 Switching Substations.......................................................................................... 39

1.6 REFERENCES................................................................................................................. 40

CHAPTER 2 - GENERAL DESIGN CONSIDERATIONS............................................................... 41

2.1 INITIAL AND ULTIMATE REQUIREMENTS ............................................................... 41

2.2 SITE CONSIDERATIONS............................................................................................... 41

2.3 ENVIRONMENTAL CONSIDERATIONS...................................................................... 42

2.3.1 General.............................................................................................................. 42

2.3.2 Weather............................................................................................................. 46

2.3.3 Altitude .............................................................................................................. 46

2.3.4 Earthquakes....................................................................................................... 47

2.3.5 Other Considerations........................................................................................... 50

2.4 INTERFACING CONSIDERATIONS.............................................................................. 51

2.4.1 Line Tension....................................................................................................... 51

2.5 RELIABILITY CONSIDERATIONS............................................................................... 51

2.6 OPERATING CONSIDERATIONS ................................................................................. 52

2.7 SAFETY CONSIDERATIONS......................................................................................... 52

2.8 MAINTENANCE CONSIDERATIONS........................................................................... 52

2.9 REFERENCES................................................................................................................. 52

CHAPTER 3 - DOCUMENTS......................................................................................................... 55

3.1 GENERAL....................................................................................................................... 55

3.1.1 Possible Documents or Studies Required of the Engineer....................................... 55

3.2 NEED FOR DOCUMENTATION.................................................................................... 55

3.3 PROCEDURES................................................................................................................ 56

3.4 PROCUREMENT............................................................................................................ 56

3.5 DRAWINGS.................................................................................................................... 57

3.5.1 General.............................................................................................................. 57

3.5.2 Quality............................................................................................................... 57

3.5.3 Types of Drawings ............................................................................................. 59

3.6 STUDIES......................................................................................................................... 71

3.7 REFERENCES................................................................................................................. 71
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APPENDIX A—TYPICAL SUBSTATION DRAWING CHECKLIST....................................... 73

APPENDIX B—U.S. DEPARTMENT OF AGRICULTURE RURAL UTILITIES

SERVICE SUBSTATION DESIGN SUMMARY....................................................................... 91

1 INTRODUCTION................................................................................................... 94

2 DESIGN CONSIDERATIONS................................................................................. 95

3 DOCUMENTS ........................................................................................................ 98

4 PHYSICAL LAYOUT........................................................................................... 100

5 MAJOR EQUIPMENT.......................................................................................... 104

6 SITE .................................................................................................................. 107

7 STRUCTURES...................................................................................................... 108

8 FOUNDATIONS................................................................................................... 109

9 GROUNDING....................................................................................................... 109

10 INSULATED CABLES AND RACEWAYS.......................................................... 111

11 CORROSION........................................................................................................ 112

12 PROTECTIVE RELAYING................................................................................... 112

13 INSTRUMENTS, TRANSDUCER, AND METERS ............................................... 114

14 SUBSTATION AUTOMATION............................................................................ 114

15 AC AND DC AUXILIARY SYSTEMS.................................................................. 115

16 CONTROL HOUSE .............................................................................................. 116

17 COMMUNICATIONS........................................................................................... 117

CHAPTER 4 - PHYSICAL LAYOUT ........................................................................................... 119

4.1 INTRODUCTION.......................................................................................................... 119

4.2 LAYOUT CONSIDERATIONS..................................................................................... 119

4.2.1 Initial Design Parameters.................................................................................. 119

4.2.2 Selection of Switching Scheme .......................................................................... 119

4.2.3 Substation Expansion......................................................................................... 119

4.2.4 Substation Profile .............................................................................................. 120

4.2.5 Underground Circuits........................................................................................ 120

4.2.6 Equipment Removal.......................................................................................... 120

4.3 DISTRIBUTION SUBSTATIONS.................................................................................. 121

4.3.1 Basic Distribution Substation.............................................................................. 121

4.3.2 Transformer Primary Protective Devices........................................................... 122

4.3.3 Voltage Regulation............................................................................................ 122

4.3.4 Circuit Breaker/Recloser Bypass Facilities......................................................... 123

4.3.5 Surge Arresters................................................................................................ 124

4.3.6 Enclosed Equipment.......................................................................................... 124

4.4 TRANSMISSION SUBSTATIONS................................................................................ 125

4.4.1 Basic Transmission Substation........................................................................... 125

4.4.2 Circuit Breaker Bypass Facilities....................................................................... 126

4.4.3 Surge Arresters................................................................................................ 126

4.4.4 Carrier Equipment............................................................................................. 127

4.4.5 Voltage Transformers....................................................................................... 127

4.4.6 Current Transformers....................................................................................... 127

4.4.7 Grounding Switches.......................................................................................... 127

4.5 SWITCHING STATIONS.............................................................................................. 127

4.5.1 Basic Switching Substation................................................................................ 128
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4.5.2 Surge Arresters................................................................................................ 128

4.6 TYPICAL BUS CONFIGURATIONS............................................................................ 128

4.6.1 Single Bus........................................................................................................ 129

4.6.2 Sectionalized Bus.............................................................................................. 132

4.6.3 Main and Transfer Bus ..................................................................................... 133

4.6.4 Ring Bus.......................................................................................................... 136

4.6.5 Breaker-and-a-Half .......................................................................................... 139

4.6.6 Double Breaker–Double Bus............................................................................. 139

4.6.7 Relative Switching Scheme Costs...................................................................... 141

4.7 PROTECTION OF SUBSTATION INSULATION......................................................... 142

4.7.1 General............................................................................................................ 142

4.7.2 Surge Protection............................................................................................... 142

4.7.3 Direct Stroke Protection.................................................................................... 142

4.8 SUBSTATION INSULATORS....................................................................................... 146

4.8.1 Outdoor Apparatus Insulators............................................................................ 146

4.8.2 Suspension Insulators........................................................................................ 151

4.9 ELECTRICAL CLEARANCES...................................................................................... 153

4.10 BARE CONDUCTORS.................................................................................................. 157

4.10.1 Conductor Materials.......................................................................................... 157

4.10.2 Rigid Conductors.............................................................................................. 157

4.10.3 Flexible Conductors........................................................................................... 159

4.10.4 Conductor Ampacity......................................................................................... 160

4.10.5 Bus Connections............................................................................................... 160

4.11 RIGID BUS DESIGN ..................................................................................................... 163

4.11.1 General Considerations...................................................................................... 163

4.11.2 Procedure for Rigid Bus Design......................................................................... 164

4.11.3 Bus Design Example ......................................................................................... 171

4.12 STRAIN BUS DESIGN.................................................................................................. 176

4.12.1 General Considerations...................................................................................... 176

4.12.2 Procedure for Strain Bus Design........................................................................ 177

4.13 APPLICATION OF MOBILE TRANSFORMERS AND SUBSTATIONS...................... 184

4.13.1 Size and Maneuverability of the Equipment......................................................... 185

4.13.2 Installation Location and Provisions.................................................................... 185

4.13.3 Electrical Clearances........................................................................................ 185

4.13.4 Primary and Secondary Connections.................................................................. 185

4.13.5 Grounding......................................................................................................... 186

4.13.6 Auxiliary System Requirements......................................................................... 186

4.13.7 Safety................................................................................................................. 186

4.14 REFERENCES............................................................................................................... 186

4.15 LEGEND FOR EQUATIONS......................................................................................... 188

CHAPTER 5 - MAJOR EQUIPMENT........................................................................................... 191

5.1 GENERAL..................................................................................................................... 191

5.2 POWER TRANSFORMERS .......................................................................................... 191

5.2.1 General............................................................................................................ 191

5.2.2 Types............................................................................................................... 192

5.2.3 Ratings............................................................................................................. 193
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5.2.4 Taps ................................................................................................................ 200

5.2.5 Impedance ....................................................................................................... 201

5.2.6 Phase Relation.................................................................................................. 201

5.2.7 Parallel Operation of Transformers.................................................................... 202

5.2.8 Dielectric Requirements.................................................................................... 204

5.2.9 Short-Circuit Requirements................................................................................ 207

5.2.10 Cooling Equipment............................................................................................ 209

5.2.11 Oil and Oil Preservation Equipment.................................................................... 210

5.2.12 Audible Sound .................................................................................................. 210

5.2.13 Tank................................................................................................................ 214

5.2.14 Accessories...................................................................................................... 214

5.2.15 Electrical Tests and Measurements.................................................................... 214

5.2.16 Shipment.......................................................................................................... 216

5.2.17 Warranty.......................................................................................................... 216

5.2.18 Core and Coils.................................................................................................. 216

5.2.19 Specifications ................................................................................................... 217

5.2.20 References....................................................................................................... 217

5.3 POWER CIRCUIT BREAKERS .................................................................................... 219

5.3.1 General............................................................................................................ 219

5.3.2 Types of Circuit Breakers................................................................................. 221

5.3.3 Ratings............................................................................................................. 226

5.3.4 Operating Mechanisms...................................................................................... 238

5.3.5 Tests................................................................................................................ 242

5.3.6 Control and Auxiliary Power Requirements........................................................ 244

5.3.7 Purchase Evaluation.......................................................................................... 244

5.3.8 Shipment and Installation................................................................................... 244

5.3.9 References....................................................................................................... 244

5.4 METAL-CLAD SWITCHGEAR..................................................................................... 245

5.4.1 General............................................................................................................ 245

5.4.2 Types............................................................................................................... 246

5.4.3 Ratings............................................................................................................. 249

5.4.4 Purchase Considerations ................................................................................... 250

5.4.5 References....................................................................................................... 252

5.5 SUBSTATION VOLTAGE REGULATORS................................................................... 252

5.5.1 General............................................................................................................ 252

5.5.2 Types............................................................................................................... 253

5.5.3 Ratings............................................................................................................. 254

5.5.4 Regulator Controls............................................................................................ 261

5.5.5 Lightning Protection.......................................................................................... 262

5.5.6 References....................................................................................................... 262

5.6 SHUNT CAPACITOR EQUIPMENT ............................................................................ 262

5.6.1 General............................................................................................................ 262

5.6.2 System Considerations ...................................................................................... 263

5.6.3 Types............................................................................................................... 267

5.6.4 Bank Configuration........................................................................................... 268

5.6.5 Ratings............................................................................................................. 269

5.6.6 Switching ......................................................................................................... 271
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5.6.7 Protection......................................................................................................... 280

5.6.8 Grounding and Short-Circuiting of Capacitor Banks............................................. 285

5.6.9 Mounting.......................................................................................................... 285

5.6.10 Factory Tests ................................................................................................... 288

5.6.11 Inspection and Maintenance .............................................................................. 288

5.6.12 Typical Technical Specification.......................................................................... 288

5.6.13 References....................................................................................................... 297

5.7 AIR SWITCHES............................................................................................................ 298

5.7.1 General............................................................................................................ 298

5.7.2 Types of Air Switches....................................................................................... 299

5.7.3 Various Constructions of Outdoor Air Switches.................................................. 301

5.7.4 Usual Service Conditions................................................................................... 308

5.7.5 Ratings............................................................................................................. 308

5.7.6 Other Requirements.......................................................................................... 312

5.7.7 Mounting Considerations ................................................................................... 322

5.7.8 References....................................................................................................... 323

5.8 SURGE ARRESTERS.................................................................................................... 323

5.8.1 General............................................................................................................ 323

5.8.2 Classification of Arresters................................................................................. 324

5.8.3 Ratings (Standard Definitions) ........................................................................... 332

5.8.4 System Voltage ................................................................................................ 333

5.8.5 Grounded vs. Ungrounded Systems.................................................................... 333

5.8.6 Application Guide for Silicon-Carbide Valve Arresters........................................ 334

5.8.7 Application Guide for Metal Oxide Surge Arresters............................................. 342

5.8.8 Location........................................................................................................... 352

5.8.9 Protection at Line Entrances.............................................................................. 356

5.8.10 References....................................................................................................... 357

5.9 AUTOMATIC CIRCUIT RECLOSERS.......................................................................... 357

5.9.1 General............................................................................................................ 357

5.9.2 Recloser Classifying Features............................................................................ 361

5.9.3 Recloser Ratings............................................................................................... 363

5.9.4 Construction..................................................................................................... 371

5.9.5 Recloser Operation........................................................................................... 373

5.9.6 Maintenance and Inspection .............................................................................. 375

5.9.7 Mounting.......................................................................................................... 376

5.9.8 References....................................................................................................... 376

5.10 INSTRUMENT TRANSFORMERS................................................................................ 377

5.10.1 General............................................................................................................ 377

5.10.2 Service Conditions ............................................................................................ 377

5.10.3 Accuracy......................................................................................................... 379

5.10.4 Secondary Burdens........................................................................................... 381

5.10.5 Construction..................................................................................................... 381

5.10.6 Current Transformers ....................................................................................... 382

5.10.7 Voltage Transformers....................................................................................... 389

5.10.8 Combination Units............................................................................................. 398

5.10.9 Tests................................................................................................................ 399

5.10.10 References....................................................................................................... 399
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5.11 COUPLING CAPACITORS AND COUPLING CAPACITOR VOLTAGE

TRANSFORMERS......................................................................................................... 400

5.11.1 General............................................................................................................ 400

5.11.2 Coupling Capacitors.......................................................................................... 400

5.11.3 Coupling Capacitor Voltage Transformers.......................................................... 401

5.11.4 Service Conditions ............................................................................................ 404

5.11.5 Ratings............................................................................................................. 404

5.11.6 Tests................................................................................................................ 408

5.11.7 References....................................................................................................... 408

5.12 MOBILE UNITS............................................................................................................ 409

5.12.1 Feasibility......................................................................................................... 409

5.12.2 Mobile Transformers......................................................................................... 409

5.12.3 Mobile Substations............................................................................................ 410

5.12.4 Phase Rotation Indicators.................................................................................. 410

5.12.5 Other Considerations......................................................................................... 410

5.12.6 Accessories Included with the Mobile Unit ......................................................... 412

CHAPTER 6 - SITE DESIGN ........................................................................................................ 413

6.1 GENERAL..................................................................................................................... 413

6.2 TYPES OF GRADED YARDS....................................................................................... 413

6.2.1 Flat Yards........................................................................................................ 414

6.2.2 Sloped Yards.................................................................................................... 414

6.2.3 Stepped Yards (Two or More Levels)................................................................ 414

6.3 PRELIMINARY REQUIREMENTS............................................................................... 414

6.4 DRAINAGE CONSIDERATIONS................................................................................. 415

6.4.1 Stormwater Management.................................................................................. 415

6.4.2 Surface Drainage System.................................................................................. 415

6.4.3 Closed Drainage System................................................................................... 415

6.4.4 Planning........................................................................................................... 415

6.4.5 Design ............................................................................................................. 415

6.5 EARTHWORK CONSIDERATIONS AND DESIGN..................................................... 419

6.5.1 Borrow ............................................................................................................ 419

6.5.2 Topsoil............................................................................................................. 419

6.5.3 Cut and Fill....................................................................................................... 421

6.5.4 Compaction...................................................................................................... 421

6.5.5 Cleanup............................................................................................................ 422

6.6 ROADS AND OTHER ACCESS.................................................................................... 422

6.6.1 General Access Roads...................................................................................... 422

6.6.2 Grade............................................................................................................... 422

6.6.3 Curvature......................................................................................................... 422

6.6.4 Design ............................................................................................................. 422

6.6.5 Railroad Spur.................................................................................................... 422

6.6.6 Roadways in the Substation Yard....................................................................... 423

6.7 EROSION PROTECTION ............................................................................................. 423

6.7.1 General............................................................................................................ 423

6.7.2 Legal Requirements.......................................................................................... 423

6.8 YARD SURFACING MATERIAL................................................................................. 423
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6.9 SECURITY FENCE....................................................................................................... 424

6.10 REFERENCES .............................................................................................................. 424

APPENDIX C—SAMPLE SUBSTATION SECURITY FENCE SPECIFICATION.................. 426

CHAPTER 7 - STRUCTURES....................................................................................................... 431

7.1 MATERIALS................................................................................................................. 431

7.1.1 Steel................................................................................................................ 431

7.1.2 Aluminum......................................................................................................... 431

7.1.3 Concrete .......................................................................................................... 432

7.1.4 Wood............................................................................................................... 432

7.2 FUNCTIONAL STRUCTURE TYPES........................................................................... 432

7.2.1 Line Support Structures..................................................................................... 432

7.2.2 Equipment Support Structures............................................................................ 432

7.2.3 Distribution Substation Structure ........................................................................ 433

7.3 STRUCTURE MEMBER TYPES................................................................................... 433

7.3.1 Lattice ............................................................................................................. 433

7.3.2 Solid Profile ...................................................................................................... 433

7.3.3 Semi-Solid Profile ............................................................................................. 434

7.3.4 Summary.......................................................................................................... 434

7.4 DESIGN ........................................................................................................................ 434

7.4.1 Design Loads ................................................................................................... 434

7.4.2 Line Support Structures..................................................................................... 434

7.4.3 Deflection Consideration ................................................................................... 435

7.4.4 Lightning Masts................................................................................................ 436

7.4.5 Equipment Support Structures............................................................................ 436

7.4.6 Base Condition ................................................................................................. 436

7.4.7 Seismic Loads .................................................................................................. 437

7.4.8 Wind Loads...................................................................................................... 439

7.4.9 Construction Loading ........................................................................................ 440

7.4.10 Loading Combination for Design........................................................................ 441

7.4.11 Typical Design Approach.................................................................................. 441

7.5 FASTENERS ................................................................................................................. 450

7.5.1 ASTM A394 .................................................................................................... 450

7.5.2 ASTM A307 .................................................................................................... 450

7.5.3 ASTM A325 .................................................................................................... 450

7.6 WELDING..................................................................................................................... 452

7.7 FINISHES...................................................................................................................... 452

7.7.1 Galvanizing....................................................................................................... 452

7.7.2 Painting............................................................................................................ 452

7.7.3 Wood Preservatives.......................................................................................... 453

7.8 COMPUTER PROGRAMS............................................................................................ 453

7.8.1 Model Geometry............................................................................................... 453

7.8.2 Load Input........................................................................................................ 454

7.8.3 Computer Output.............................................................................................. 454

7.9 REFERENCES ................................................................................................................ 455

APPENDIX D—RISA-3D INPUT AND OUTPUT FOR A SIMPLE “T” STRUCTURE.......... 458
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CHAPTER 8 - FOUNDATIONS.................................................................................................... 465

8.1 GENERAL..................................................................................................................... 465

8.2 SOIL INFORMATION................................................................................................... 465

8.2.1 General............................................................................................................ 465

8.2.2 Soil Classification.............................................................................................. 466

8.2.3 Bearing Values................................................................................................. 466

8.2.4 Groundwater Level........................................................................................... 467

8.2.5 Differential Settlement ...................................................................................... 467

8.2.6 Chemical Tests................................................................................................. 468

8.2.7 Seismic Evaluation............................................................................................ 468

8.3 FOUNDATION TYPES................................................................................................. 468

8.3.1 Drilled Shafts (Piers)......................................................................................... 468

8.3.2 Drilled Shaft Design.......................................................................................... 469

8.3.3 Drilled Shaft Design (Line Support Structure)..................................................... 475

8.3.4 Compression and Uplift Capacity (Drilled Shafts)................................................ 478

8.3.5 Spread Footings................................................................................................ 482

8.3.6 Slabs on Grade ................................................................................................. 489

8.4 OIL POLLUTION.......................................................................................................... 492

8.4.1 Basic Retention System..................................................................................... 493

8.4.2 Oil Separator Tank............................................................................................ 493

8.4.3 Summary.......................................................................................................... 494

8.5 REFERENCES ............................................................................................................... 494

APPENDIX E—SPECIFICATION FOR PROCURING GEOTECHNICAL

SUBSURFACE INVESTIGATION.......................................................................................... 497

CHAPTER 9 - GROUNDING........................................................................................................ 501

9.1 GENERAL..................................................................................................................... 501

9.2 DEFINITIONS............................................................................................................... 503

9.2.1 DC Offset........................................................................................................ 503

9.2.2 Earth Current ................................................................................................... 503

9.2.3 Ground Fault Current ........................................................................................ 503

9.2.4 Ground Potential Rise (GPR)............................................................................. 503

9.2.5 Mesh Voltage ................................................................................................... 503

9.2.6 Soil Resistivity .................................................................................................. 503

9.2.7 Step Voltage..................................................................................................... 503

9.2.8 Touch Voltage .................................................................................................. 503

9.2.9 Transferred Voltage.......................................................................................... 503

9.3 SOIL RESISTIVITY MEASUREMENTS....................................................................... 504

9.3.1 Analyzing Soil Resistivity Measurements............................................................ 505

9.3.2 Uniform Soil Assumption................................................................................... 506

9.4 AREA OF THE GROUND GRID................................................................................... 506

9.5 GROUND FAULT CURRENTS..................................................................................... 506

9.5.1 Symmetrical Grid Current.................................................................................. 510

9.5.2 Determine the Split Factor, Sf............................................................................. 510

9.5.3 The Decrement Factor, Df................................................................................. 533

9.5.4 Maximum Grid Current ..................................................................................... 534

9.5.5 Asymmetrical Fault........................................................................................... 534
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9.6 GROUND CONDUCTOR.............................................................................................. 535

9.6.1 Conductor Material........................................................................................... 535

9.6.2 Ground Conductor Sizing................................................................................... 535

9.6.3 Sizing Equipment Ground Conductor................................................................... 536

9.6.4 Sizing Ground Grid Conductors.......................................................................... 537

9.6.5 Additional Conductor Sizing Factors................................................................... 537

9.6.6 Connections from Equipment and Structures to Ground Grid ................................ 537

9.7 SAFETY CONSIDERATIONS....................................................................................... 538

9.7.1 Tolerable Limits of Body Current....................................................................... 539

9.7.2 Typical Shock Situations.................................................................................... 540

9.8 TOLERABLE TOUCH AND STEP VOLTAGES........................................................... 540

9.9 PROTECTIVE SURFACE MATERIAL AND REDUCTION FACTOR CS .................... 545

9.9.1 Reduction Factor Cs.......................................................................................... 546

9.10 DESIGN OF A SUBSTATION GROUNDING SYSTEM................................................ 548

9.10.1 General Concepts............................................................................................. 548

9.10.2 Design Procedures............................................................................................ 548

9.10.3 Preliminary Design............................................................................................ 550

9.10.4 Calculate Design Mesh Voltage ......................................................................... 551

9.10.5 Step Voltage (Es).............................................................................................. 553

9.10.6 Ground Potential Rise (GPR)............................................................................. 554

9.10.7 Design Modifications......................................................................................... 555

9.10.8 Application of Equations for Em and Es............................................................... 557

9.10.9 Use of Computer Analysis in Grid Design........................................................... 557

9.10.10 Special Danger Points....................................................................................... 557

9.10.11 Investigation of Transferred Voltage .................................................................. 561

9.10.12 Effect of Sustained Ground Currents.................................................................. 562

9.11 REFERENCES............................................................................................................... 562

CHAPTER 10 - INSULATED CABLES AND RACEWAYS......................................................... 563

10.1 GENERAL..................................................................................................................... 563

10.2 600-VOLT CABLE ........................................................................................................ 563

10.2.1 Circuit Requirements......................................................................................... 563

10.2.2 Conductors....................................................................................................... 564

10.2.3 Conductor Configurations.................................................................................. 564

10.2.4 Conductor Insulation and Jackets....................................................................... 566

10.2.5 Cable Sizing...................................................................................................... 567

10.2.6 Segregation of Control Cables............................................................................ 567

10.2.7 Installation Considerations ................................................................................. 569

10.3 POWER CABLE OVER 600 VOLTS............................................................................. 570

10.3.1 Medium-Voltage Shielded Power Cable (2 kV up to 35 kV) ................................ 570

10.3.2 Conductors....................................................................................................... 570

10.3.3 Conductor Shield............................................................................................... 570

10.3.4 Insulation.......................................................................................................... 571

10.3.5 Insulation Shield................................................................................................ 571

10.3.6 Jackets............................................................................................................. 571

10.3.7 Cable Voltage Rating........................................................................................ 572

10.3.8 Conductor Sizing............................................................................................... 572
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10.3.9 Terminations and Splices................................................................................... 573

10.3.10 Cable Segregation............................................................................................. 573

10.3.11 Installation Considerations ................................................................................. 573

10.3.12 High-Voltage Power Cable (69 kV up to 230 kV)............................................... 574

10.4 SPECIALIZED CABLE................................................................................................. 574

10.5 RACEWAYS................................................................................................................. 575

10.5.1 Function........................................................................................................... 575

10.5.2 Economics........................................................................................................ 575

10.6 UNDERGROUND RACEWAYS................................................................................... 576

10.6.1 Direct-Buried Cable .......................................................................................... 576

10.6.2 Direct-Buried Conduit ....................................................................................... 577

10.6.3 Concrete-Encased Conduit (Duct Bank)............................................................. 578

10.6.4 Cable Trenches ................................................................................................ 582

10.6.5 Manholes......................................................................................................... 584

10.6.6 Handholes........................................................................................................ 584

10.7 RACEWAY COMBINATION ....................................................................................... 585

10.8 SUMMARY—UNDERGROUND RACEWAYS............................................................ 586

10.9 OVERHEAD RACEWAYS........................................................................................... 586

10.9.1 Cable Trays...................................................................................................... 587

10.9.2 Cable Duct....................................................................................................... 587

10.9.3 Plastic Conduit.................................................................................................. 587

10.9.4 Metal Conduit................................................................................................... 587

10.9.5 Above-Grade Cable Trench............................................................................... 588

10.10 SUMMARY—OVERHEAD RACEWAYS.................................................................... 588

10.11 RACEWAY MATERIALS............................................................................................. 588

10.11.1 Plastic .............................................................................................................. 588

10.11.2 Fiber................................................................................................................ 588

10.12 RACEWAY SIZING...................................................................................................... 588

10.13 REFERENCES............................................................................................................... 589

CHAPTER 11 - CORROSION....................................................................................................... 591

11.1 GENERAL..................................................................................................................... 591

11.1.1 Characteristics of Corrosion .............................................................................. 591

11.1.2 Dissimilar Metals.............................................................................................. 591

11.1.3 Dissimilar Environments.................................................................................... 592

11.2 PRELIMINARY PREVENTIVE MEASURES ............................................................... 593

11.2.1 Surveys............................................................................................................ 593

11.2.2 Selection of Materials........................................................................................ 594

11.3 TESTING AND INSTALLATION ................................................................................. 595

11.3.1 Earth Resistivity Measurements......................................................................... 595

11.3.2 Soil Samples..................................................................................................... 595

11.3.3 Anode Locations............................................................................................... 595

11.3.4 Underground Connections ................................................................................. 595

11.3.5 Estimating Corrosion Conditions from DC Potential Measurements...................... 595

11.4 REFERENCES............................................................................................................... 598
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CHAPTER 12 - PROTECTIVE RELAYING.................................................................................. 601

12.1 GENERAL..................................................................................................................... 601

12.1.1 Purpose of Protective Relays............................................................................. 601

12.1.2 Design Objectives............................................................................................. 601

12.1.3 Indications of Defective Equipment or Abnormal Conditions................................ 601

12.2 FUNDAMENTAL CONSIDERATIONS........................................................................ 603

12.2.1 Phasors............................................................................................................ 603

12.2.2 Polarity ............................................................................................................ 603

12.2.3 Faults............................................................................................................... 603

12.2.4 Symmetrical Components.................................................................................. 604

12.2.5 Relay Input Sources.......................................................................................... 604

12.3 BASIC RELAY TYPES................................................................................................. 604

12.3.1 General............................................................................................................ 604

12.3.2 Relay Selection................................................................................................. 607

12.3.3 Overcurrent Relay............................................................................................ 609

12.3.4 Distance Relay................................................................................................. 609

12.3.5 Differential Relay............................................................................................. 611

12.3.6 Overvoltage Relay............................................................................................ 612

12.3.7 Undervoltage Relay.......................................................................................... 612

12.3.8 Power Relay .................................................................................................... 612

12.3.9 Directional Overcurrent Relay........................................................................... 612

12.3.10 Frequency Relay............................................................................................... 612

12.3.11 Thermal Relay.................................................................................................. 613

12.3.12 Pressure Relay................................................................................................. 613

12.3.13 Auxiliary Relay................................................................................................. 613

12.4 RELAY SCHEMES........................................................................................................ 613

12.4.1 General............................................................................................................ 613

12.4.2 Transmission Line Protection............................................................................. 614

12.4.3 Distribution Feeder............................................................................................ 624

12.4.4 Major Equipment .............................................................................................. 626

12.4.5 Reclosing ......................................................................................................... 631

12.4.6 Coordination..................................................................................................... 633

12.5 REFERENCES.............................................................................................................. 635

APPENDIX F—STANDARD DEVICE FUNCTION NUMBERS............................................ 637

APPENDIX G—SUGGESTED SUFFIX LETTERS.................................................................. 646

CHAPTER 13 - INSTRUMENTS, TRANSDUCERS, AND METERS ............................................ 651

13.1 INTRODUCTION.......................................................................................................... 651

13.2 INSTRUMENTS AND TRANSDUCERS....................................................................... 651

13.2.1 Definitions........................................................................................................ 651

13.2.2 Types of Instruments and Transducers............................................................... 651

13.2.3 Classification of Instruments.............................................................................. 651

13.2.4 Components of Instruments and Transducers...................................................... 651

13.2.5 Analog Instrument Scales.................................................................................. 652

13.2.6 Operating Procedures....................................................................................... 653

13.3 METERS........................................................................................................................ 654

13.3.1 Definition ......................................................................................................... 654
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13.3.2 Types of Electric Meters................................................................................... 654

13.3.3 Demand Meter................................................................................................. 654

13.3.4 Combination Watt-Hour and Demand Meters..................................................... 655

13.3.5 Types of Meter Indicating and Recording Devices.............................................. 655

13.3.6 Connection of Watt-Hour and VAR-Hour Meters............................................... 656

13.4 MULTI-FUNCTION METERS....................................................................................... 657

13.4.1 Definition ......................................................................................................... 657

13.4.2 Input Quantities................................................................................................ 658

13.4.3 Measured and Calculated Values....................................................................... 658

13.4.4 Communications ............................................................................................... 658

13.5 REFERENCES............................................................................................................... 658

CHAPTER 14 - SUBSTATION AUTOMATION........................................................................... 659

14.1 INTRODUCTION.......................................................................................................... 659

14.2 OPEN VS. PROPRIETARY SYSTEMS......................................................................... 659

14.3 SUBSTATION AUTOMATION ARCHITECTURE....................................................... 660

14.4 DATA ACQUISITION AND CONTROL ELEMENTS.................................................. 660

14.4.1 Substation Host Processor................................................................................. 661

14.4.2 Intelligent Electronic Devices............................................................................. 663

14.4.3 Programmable Logic Controllers........................................................................ 664

14.4.4 Data Concentrator ............................................................................................ 665

14.4.5 Substation Local Area Network......................................................................... 665

14.4.6 Communication Protocols.................................................................................. 666

14.5 REFERENCES............................................................................................................... 669

APPENDIX H—GLOSSARY OF TERMS............................................................................... 671

CHAPTER 15 - AC AND DC AUXILIARY SYSTEMS................................................................. 673

15.1 AC AUXILIARY SYSTEM............................................................................................ 673

15.1.1 Typical Loads Supplied...................................................................................... 673

15.1.2 Design Requirements........................................................................................ 673

15.1.3 Equipment........................................................................................................ 678

15.1.4 Summary.......................................................................................................... 680

15.2 DC AUXILIARY SYSTEM............................................................................................ 680

15.2.1 Typical Loads Supplied...................................................................................... 680

15.2.2 Design Requirements........................................................................................ 681

15.2.3 Types of Cells .................................................................................................. 681

15.2.4 Typical Loads and Duty Cycle ........................................................................... 682

15.2.5 Equipment........................................................................................................ 683

15.3 REFERENCES............................................................................................................... 686

CHAPTER 16 - CONTROL HOUSES ........................................................................................... 689

16.1 INTRODUCTION.......................................................................................................... 689

16.2 CONTROL HOUSE CONSTRUCTION......................................................................... 689

16.2.1 Foundation........................................................................................................ 689

16.2.2 Floor................................................................................................................ 689

16.2.3 Superstructure .................................................................................................. 690

16.3 CONTROL HOUSE LAYOUT ...................................................................................... 692
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16.3.1 Control and Relay Panels .................................................................................. 692

16.3.2 DC Equipment.................................................................................................. 695

16.3.3 AC Equipment.................................................................................................. 695

16.3.4 Cableways ....................................................................................................... 695

16.3.5 Cable Entrance................................................................................................. 696

16.3.6 Lighting............................................................................................................ 697

16.3.7 Control House HVAC Systems ......................................................................... 697

16.3.8 Control House Plumbing.................................................................................... 698

16.3.9 Communications ............................................................................................... 698

16.4 REFERENCES............................................................................................................... 698

CHAPTER 17 - COMMUNICATIONS.......................................................................................... 699

17.1 INTRODUCTION.......................................................................................................... 699

17.2 APPLICATIONS........................................................................................................... 699

17.2.1 Relaying........................................................................................................... 699

17.2.2 SCADA........................................................................................................... 699

17.2.3 Telemetering .................................................................................................... 700

17.2.4 Voice............................................................................................................... 700

17.3 METHODS.................................................................................................................... 700

17.3.1 Power Line Carrier........................................................................................... 700

17.3.2 Audio Tone ...................................................................................................... 705

17.3.3 Carrier or Audio Tone on Shield Wire ................................................................ 706

17.3.4 Microwave ....................................................................................................... 706

17.3.5 Optical Fiber..................................................................................................... 709

17.3.6 Wire Lines....................................................................................................... 711

17.3.7 Satellite Communications................................................................................... 712

17.4 REFERENCES............................................................................................................... 714

APPENDIX I—GLOSSARY OF TERMS ................................................................................ 715

CHAPTER 18 - INSPECTION....................................................................................................... 717

18.1 PURPOSE ..................................................................................................................... 717

18.2 GENERAL..................................................................................................................... 717

18.2.1 Records ........................................................................................................... 717

18.2.2 Safety .............................................................................................................. 717

18.3 PERIODIC INSPECTIONS............................................................................................ 718

18.3.1 Visual Inspections............................................................................................. 719

18.3.2 Inspection with Diagnostic Online Test Equipment .............................................. 723

18.3.3 Detailed Inspection of Major Equipment............................................................. 726

18.3.4 Internal Inspection of Transformers and Regulators............................................ 728

18.4 NON-PERIODIC INSPECTIONS.................................................................................. 729

18.4.1 Inspection of Porcelain...................................................................................... 729

18.4.2 Fuses, Disconnects, and Other Switches............................................................. 730

18.4.3 Buses............................................................................................................... 730

18.4.4 Transformers.................................................................................................... 730

18.4.5 Transformer On-Load Tap Changers................................................................. 730

18.4.6 Regulators........................................................................................................ 730

18.4.7 Oil Circuit Reclosers......................................................................................... 730
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18.4.8 Circuit Breakers............................................................................................... 730

18.4.9 Grounding System............................................................................................. 730

18.4.10 Structures......................................................................................................... 730

18.5 REFERENCES............................................................................................................... 731

CHAPTER 19 - TESTS.................................................................................................................. 733

19.1 GENERAL..................................................................................................................... 733

19.1.1 Records ........................................................................................................... 733

19.1.2 Safety .............................................................................................................. 733

19.2 DETAILED REQUIREMENTS...................................................................................... 734

19.2.1 Acceptance Tests............................................................................................. 734

19.2.2 Periodic Tests................................................................................................... 734

19.2.3 Tests After Failure............................................................................................ 734

19.3 DESCRIPTION OF TESTS............................................................................................ 734

19.3.1 Insulation Resistance Test................................................................................. 734

19.3.2 Power Factor Test............................................................................................ 737

19.3.3 DC High Potential Test..................................................................................... 737

19.3.4 Dielectric Absorption Test................................................................................. 739

19.3.5 AC Over-Potential Test .................................................................................... 740

19.3.6 Contact Resistance Test.................................................................................... 740

19.3.7 Winding Resistance Test................................................................................... 740

19.3.8 Insulating Oil Tests........................................................................................... 741

19.3.9 Combustible Gas Analysis ................................................................................. 742

19.3.10 SF6 Gas Analyses............................................................................................. 742

19.3.11 Timing Test...................................................................................................... 742

19.3.12 Motion Analyzer Test........................................................................................ 743

19.3.13 Series Overcurrent Test.................................................................................... 743

19.3.14 Turns Ratio Test............................................................................................... 743

19.3.15 Polarity Test..................................................................................................... 743

19.3.16 Protective Relay System Tests.......................................................................... 743

19.3.17 Meter Calibration Tests..................................................................................... 744

19.3.18 Capacitance Test.............................................................................................. 744

19.3.19 Pressure Test ................................................................................................... 744

19.3.20 Ground Grid Resistance Measurement ............................................................... 745

19.4 REFERENCES............................................................................................................... 745

CHAPTER 20 - MAINTENANCE................................................................................................. 747

20.1 GENERAL..................................................................................................................... 747

20.1.1 Records ........................................................................................................... 747

20.1.2 Safety .............................................................................................................. 747

20.2 PERIODIC MAINTENANCE........................................................................................ 747

20.2.1 Specific Requirements....................................................................................... 748

20.2.2 Painting............................................................................................................ 749

20.3 UNSCHEDULED MAINTENANCE.............................................................................. 750

20.4 RELIABILITY-CENTERED MAINTENANCE.............................................................. 751

20.4.1 Methods........................................................................................................... 751

20.4.2 Application....................................................................................................... 752
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20.4.3 Conclusion........................................................................................................ 754

20.5 REFERENCES............................................................................................................... 754

CHAPTER 21 - UPRATING AND EXPANDING EXISTING SUBSTATIONS.............................. 755

21.1 APPLICABILITY.......................................................................................................... 755

21.2 FEASIBILITY................................................................................................................ 755

21.3 SUBSTATION UPRATING........................................................................................... 755

21.3.1 Major Equipment Uprating................................................................................. 756

21.4 SUBSTATION EXPANSION......................................................................................... 758

21.4.1 General............................................................................................................ 758

21.4.2 Site Work......................................................................................................... 760

21.4.3 Grounding......................................................................................................... 760

21.4.4 Raceway System.............................................................................................. 760

21.4.5 Control House .................................................................................................. 761

21.4.6 Equipment........................................................................................................ 761

21.5 PLANNING FOR UPRATING OR EXPANSION.......................................................... 762

21.6 COMPARISONS—NEW VS. UPRATING OR EXPANSION........................................ 763

21.7 SUBSTATION UPGRADING........................................................................................ 763

21.8 REFERENCES............................................................................................................... 764
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LIST OF FIGURES

These exhibits are available electronically as well as in hard copy.

FIGURE TITLE 

2-1 Basic Wind Speed..................................................................................................... 48

2-2 Seismic Zone Map of the United States...................................................................... 50

3-1 Power Transformer .................................................................................................. 60

3-2 Three-Phase Transformer with Tertiary..................................................................... 60

3-3 Three-Phase Auto-Transformer................................................................................. 60

3-4 Step Voltage Regulator with Bypass Switch............................................................... 61

3-5 Hook Stick-Operated Disconnecting Switch................................................................ 61

3-6 Three-Phase Gang-Operated Disconnecting Switch with Horn Gaps and

Grounding Switch...................................................................................................... 61

3-7 Three-Phase Double Side-Break Disconnecting Switch with Motor Operator ............... 62

3-8 Fused Disconnect..................................................................................................... 62

3-9 Oil Circuit Recloser................................................................................................... 63

3-10 Circuit Breaker......................................................................................................... 63

3-11 Surge Arrester.......................................................................................................... 63

3-12 Voltage Transformer................................................................................................. 64

3-13 Current Transformer................................................................................................. 64

3-14 Coupling Capacitor with Voltage Transformer ............................................................ 64

3-15 Coupling Capacitor, Wave Trap, Tuning Unit, and Power Line Carrier

Transmitter/Receiver ................................................................................................ 64

3-16 Disconnecting Clamp ................................................................................................ 65

3-17 Shunt Capacitor ........................................................................................................ 65

3-18 One-Line Diagram Symbols....................................................................................... 66

3-19 Typical Relay and Meter Representation.................................................................... 67

3-20 Conceptual One-Line Diagram.................................................................................. 68

3-21 Partial Switching One-Line Diagram.......................................................................... 69

3-22 Partial Functional Relaying One-Line Diagram............................................................ 70

4-1 Substation Plan View Showing Space for Equipment Removal................................... 121

4-2 Basic Distribution Substation.................................................................................... 122

4-3 Voltage Regulator Bypass Arrangements................................................................. 123

4-4 Typical Circuit Breaker/Recloser Bypass Arrangement............................................. 124

4-5 Use of Tandem Switches for Circuit Breaker/Recloser Bypassing ............................. 124

4-6 Basic Transmission Substation................................................................................. 125

4-7 Typical Circuit Breaker Bypass Arrangement........................................................... 126

4-8 Basic Switching Substation...................................................................................... 128

4-9 Single Bus—Low Profile ......................................................................................... 130

4-10 Single Bus—High Profile......................................................................................... 131

4-11 Sectionalized Bus.................................................................................................... 132

4-12 Main and Transfer Bus—Low Profile ...................................................................... 134

4-13 Main and Transfer Bus—High Profile ...................................................................... 135

4-14 Ring Bus................................................................................................................ 137

4-15 Breaker-and-a-Half ................................................................................................ 138
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FIGURE TITLE 

4-16 Double Breaker–Double Bus................................................................................... 140

4-17 Zones of Protection for Masts and Shield Wires Using Fixed Angle Method............... 143

4-18 Principle of Rolling Sphere....................................................................................... 144

4-19 Station Post Insulator .............................................................................................. 148

4-20 Suspension Insulator................................................................................................ 152

4-21 Safety Clearance to Electric Supply Station Fences................................................... 158

4-22 Drag Coefficients for Structural Shapes................................................................... 166

4-23 Typical Bus System Illustrating Provisions for Conductor Thermal Expansion ............. 169

4-24 Coupler Location .................................................................................................... 175

4-25 Bus Configuration for Example ................................................................................ 176

4-26 Short Strain Bus Insulator Effect.............................................................................. 180

5-1 Methods of Oil Preservation.................................................................................... 211

5-2 “Dead Tank” Breaker............................................................................................. 222

5-3 “Live Tank” Breaker.............................................................................................. 222

5-4 Three-Pole Single-Throw Breakers.......................................................................... 223

5-5 SF6 Gas Circuit Breakers........................................................................................ 224

5-6 Type SDV Vacuum Circuit Breaker ........................................................................ 225

5-7 Relation of Symmetrical Interrupting Capability, Closing Capability, Latching

Capability, and Carrying Capability to Rated Short-Circuit Current ............................. 235

5-8 Ratio of Circuit Breaker Asymmetrical to Symmetrical Interrupting Capabilities.......... 236

5-9 Single-Aisle Metal-Clad Switchgear with Ancillaries................................................. 247

5-10 Typical Single-Aisle Switchgear Installation.............................................................. 248

5-11 Single-Phase Voltage Regulator............................................................................... 255

5-12 Three-Phase Voltage Regulator............................................................................... 256

5-13 Typical Capacitor Bank—Two Three-Phase Capacitor Racks Connected to

Form a Two-Step Bank, Floating Wye with a Common Neutral................................. 264

5-14 A Y-Y Connected Capacitor Bank with One Series Section per Phase and

Neutrals Isolated..................................................................................................... 270

5-15 Typical Capacitor Bank Grd Wye Connected............................................................ 273

5-16 Typical Capacitor Bank Floating Wye ...................................................................... 274

5-17 Typical Capacitor Bank Wye Wye Connected.......................................................... 275

5-18 A Complete Typical Capacitor Equipment Connected Grd Wye with Two

Series Sections/Phase in a Single Stack.................................................................... 276

5-19 Typical Internally and Externally Fused Capacitor Units............................................ 281

5-20 Capacitors Vertically Mounted................................................................................. 286

5-21 Capacitors Horizontally Mounted............................................................................. 287

5-22 Horizontally Mounted Double-Break Switch with Grounding Switch........................... 300

5-23 Horizontally Mounted Double-Break Switch............................................................. 300

5-24 Horizontally Mounted Vertical-Break Interrupter Switch........................................... 301

5-25 Vertically Mounted Vertical-Break Switch............................................................... 304

5-26 Tilting Insulator Switch............................................................................................ 305

5-27 Single Side-Break Switch........................................................................................ 306

5-28 Underhung Center-Break V-Switch......................................................................... 306

5-29 Hook Stick Switches on Structure at Termination of Bus from Transformer................ 307

5-30 Vertical Reach Switch ............................................................................................ 307
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FIGURE TITLE 

5-31 Arrangement of Bolt Hole Centerlines in Terminal Pads............................................ 315

5-32 Outdoor Air Switch Hook Dimensions...................................................................... 322

5-33 Coefficient of Grounding for Various System Conditions............................................ 336

5-34 Typical Voltage–Time Curve for Coordination of Arrester Protective Levels

with Insulation Withstand Strength for Liquid-Filled Transformers.............................. 338

5-35 Typical Volt–Time Curves for Coordination of Metal Oxide Surge Arrester

Protective Levels with Insulation Withstand Strength................................................. 341

5-36 Gapless Metal Oxide Surge Arrester........................................................................ 342

5-37 Shunt-Gapped Metal Oxide Surge Arrester............................................................... 343

5-38 Series-Gapped Metal Oxide Surge Arrester.............................................................. 343

5-39 Typical 60-Hz Temporary Overvoltage Capability for Metal Oxide Arresters.............. 345

5-40 Typical Volt–Time Curve for Coordination of Arrester Protective Levels with

Insulation Withstand Strength for Liquid-Filled Transformers..................................... 348

5-41 Typical Volt–Time Curves for Coordination of 152-kV MCOV Metal Oxide

Surge Arrester Protective Levels with Insulation Withstand Strength.......................... 350

5-42 Typical Volt–Time Curves for Coordination of 140-kV MCOV Metal Oxide

Surge Arrester Protective Levels with Insulation Withstand Strength.......................... 351

5-43 Maximum Safe Separation Distance of Lightning Arresters from Protected

Equipment—Nominal System Voltage 23 kV Through 46 kV..................................... 353

5-44 Maximum Safe Separation Distance of Lightning Arresters from Protected

Equipment—Nominal System Voltage 69 kV Through 138 kV................................... 354

5-45 Maximum Safe Separation Distance of Lightning Arresters from Protected

Equipment—Nominal System Voltage 161 kV Through 345 kV ................................. 355

5-46 Typical Single-Phase Hydraulically Controlled Oil Circuit Breaker.............................. 358

5-47 Recloser with Single-Phase Tripping and Three-Phase Lockout................................. 359

5-48 Typical Line Diagram of Distribution Circuit Showing Application of Reclosers........... 360

5-49 Operating Mechanism with Housing Cover Removed................................................ 372

5-50 Unit Operation........................................................................................................ 373

5-51 Recloser Operating Sequence Upon Occurrence of a Permanent Fault ...................... 374

5-52 Mounted Recloser................................................................................................... 376

5-53 55oC Rise Current Transformer Basic Loading Characteristics (in Air) ...................... 380

5-54 Bushing, Window, and Wound-Type Current Transformers....................................... 383

5-55 High-Voltage Current Transformers......................................................................... 384

5-56 Voltage Transformers............................................................................................. 390

5-57 Typical Primary Connections for Voltage Transformers............................................ 397

5-58 Coupling Capacitor with Carrier Accessories............................................................ 400

5-59 Typical Coupling Capacitor Voltage Transformer with Carrier Coupling

Accessories............................................................................................................ 402

5-60 Coupling Capacitor Voltage Transformers with and Without Wave Trap.................... 405

6-1 Flat Yard................................................................................................................ 413

6-2 Sloped Yard on Moderately Sloped Site.................................................................... 413

6-3 Stepped Yard ......................................................................................................... 414

6-4 2-Year, 30-Minute Rainfall Intensity (cm/hr)............................................................. 417

6-5 2-Year, 30-Minute Rainfall Intensity (inches/hr)........................................................ 417

6-6 Fence Erection Details............................................................................................ 430
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FIGURE TITLE 

7-1 Single-Phase Bus Support........................................................................................ 442

7-2 Tubular Structure—Short-Circuit Loading................................................................. 443

7-3 Tubular Structure—Wind Loading............................................................................ 443

7-4 Tubular Structure—Ice Loading............................................................................... 444

7-5 Tubular Structure—Seismic Loading........................................................................ 445

7-6 Tubular Structure—Deflection Equivalent Loadings .................................................. 446

7-7 Lattice Structure..................................................................................................... 448

7-8 Lattice Structure—Short-Circuit Loading.................................................................. 448

7-9 Lattice Structure—Wind Loading............................................................................. 449

8-1 Drilled Shaft Force and Moment Diagrams............................................................... 473

8-2 Drilled Shaft Elevation—Example ............................................................................ 473

8-3 Drilled Shaft Section ............................................................................................... 476

8-4 Drilled Shaft Elevation—General............................................................................. 477

8-5 “Alpha” Function for Drilled Shafts.......................................................................... 480

8-6 Approximate Frost-Depth Contours of the United States........................................... 483

8-7 Spread Footing—General........................................................................................ 484

8-8 Spread Footing with e < b/6..................................................................................... 485

8-9 Spread Footing with e > b/6..................................................................................... 485

8-10 Spread Footing Elevation......................................................................................... 486

8-11 Spread Footing Plan................................................................................................ 487

8-12 Spread Footing—3D Example.................................................................................. 487

8-13 Spread Footing—2D Example.................................................................................. 488

8-14 Transformer Slab Loading....................................................................................... 492

8-15 Oil Separator Tank.................................................................................................. 494

9-1 Wenner Four-Pin Method........................................................................................ 505

9-2 Fault Within Local Substation, Local Neutral Grounded............................................. 507

9-3 Fault Within Local Substation, Neutral Grounded at Remote Location......................... 507

9-4 Fault in Substation, System Grounded at Local Substation and Also at Other Points..... 508

9-5 Typical Current Division for a Fault on High Side of Distribution Substation................ 509

9-6 Approximate Split Factor Sf, 100% Remote, 1 Transmission Line, Low Line

Ground Resistance.................................................................................................. 511

9-7 Approximate Split Factor Sf, 100% Remote, 1 Transmission Line, High Line

Ground Resistance.................................................................................................. 512

9-8 Approximate Split Factor Sf, 100% Remote, 2 Transmission Lines, Low Line

Ground Resistance.................................................................................................. 513

9-9 Approximate Split Factor Sf, 100% Remote, 2 Transmission Lines, High Line

Ground Resistance.................................................................................................. 514

9-10 Approximate Split Factor Sf, 100% Remote, 4 Transmission Lines, Low Line

Ground Resistance.................................................................................................. 515

9-11 Approximate Split Factor Sf, 100% Remote, 4 Transmission Lines, High Line

Ground Resistance.................................................................................................. 516

9-12 Approximate Split Factor Sf, 100% Remote, 8 Transmission Lines, Low Line

Ground Resistance.................................................................................................. 517

9-13 Approximate Split Factor Sf, 100% Remote, 8 Transmission Lines, High Line

Ground Resistance.................................................................................................. 518
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FIGURE TITLE 

9-14 Approximate Split Factor Sf, 100% Remote, 12 Transmission Lines, Low Line

Ground Resistance.................................................................................................. 519

9-15 Approximate Split Factor Sf, 100% Remote, 12 Transmission Lines, High Line

Ground Resistance.................................................................................................. 520

9-16 Approximate Split Factor Sf, 100% Remote, 16 Transmission Lines, Low Line

Ground Resistance.................................................................................................. 521

9-17 Approximate Split Factor Sf, 100% Remote, 16 Transmission Lines, High Line

Ground Resistance.................................................................................................. 522

9-18 Approximate Split Factor Sf, 100% Remote, No Feeder, Low Line Ground

Resistance.............................................................................................................. 523

9-19 Approximate Split Factor Sf, 100% Remote, No Feeder, High Line Ground

Resistance.............................................................................................................. 524

9-20 Approximate Split Factor Sf, 100% Remote, No Transmission Line, Low Line

Ground Resistance.................................................................................................. 525

9-21 Approximate Split Factor Sf, 100% Remote, No Transmission Line, High Line

Ground Resistance.................................................................................................. 526

9-22 Approximate Split Factor Sf, 75% Remote, No Feeder, Low Line Ground

Resistance.............................................................................................................. 527

9-23 Approximate Split Factor Sf, 75% Remote, No Feeder, High Line Ground

Resistance.............................................................................................................. 528

9-24 Approximate Split Factor Sf, 50% Remote, No Feeder, Low Line Ground

Resistance.............................................................................................................. 529

9-25 Approximate Split Factor Sf, 50% Remote, No Feeder, High Line Ground

Resistance.............................................................................................................. 530

9-26 Approximate Split Factor Sf, 25% Remote, No Feeder, Low Line Ground

Resistance.............................................................................................................. 531

9-27 Approximate Split Factor Sf, 25% Remote, No Feeder, High Line Ground

Resistance.............................................................................................................. 532

9-28 Basic Shock Situations ............................................................................................ 541

9-29 Typical Situation of External Transferred Potential.................................................... 542

9-30 Exposure to Touch Voltage ..................................................................................... 540

9-31 Impedances in Touch Voltage Circuit....................................................................... 543

9-32 Touch Voltage Circuit ............................................................................................. 543

9-33 Exposure to Step Voltage ........................................................................................ 543

9-34 Step Voltage Circuit................................................................................................ 544

9-35 CS vs. hS ................................................................................................................ 547

9-36 Typical Chain Link Fence........................................................................................ 559

9-37 Typical Switch Grounding........................................................................................ 560

10-1 Voltage Drop for Current Transformer Circuits........................................................ 568

10-2 Construction of Shielded Power Cable ...................................................................... 570

10-3 Duct Bank Position Factors..................................................................................... 579

10-4 Monolithic Duct Bank Construction.......................................................................... 580

10-5 Tier Duct Bank Construction Cubic Yards of Grout for100 Trench Feet..................... 581

10-6 Block Trench, Cast Concrete Similar........................................................................ 583

10-7 Precast Cable Trench ............................................................................................. 584

10-8 Suggested Handhole Design .................................................................................... 585
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FIGURE TITLE 

10-9 Trench to Handhole Conduit Installation ................................................................... 586

11-1 Dissimilar Metal Corrosion—Old Steel vs. New Steel............................................... 592

11-2 Dissimilar Environment Corrosion—More Oxygen vs. Less Oxygen.......................... 593

11-3 Dissimilar Environment Corrosion—Different Soil Types........................................... 593

11-4 DC Potential Measurement for Indication of Corrosion Conditions ............................. 596

11-5 Copper–Copper Sulfate Half-Cell ............................................................................ 597

11-6 Voltage Drop Measurement to Determine Direct Current Flow ................................. 598

11-7 Neutral-to-Earth Resistance Measurements.............................................................. 599

12-1 Logical Representation of Protective Relays............................................................. 604

12-2 Overcurrent Protective Characteristic ...................................................................... 610

12-3 Distance Protective Characteristic ........................................................................... 610

12-4 Differential Relay Principle...................................................................................... 611

12-5 Open Differential.................................................................................................... 616

12-6 Distance Relay Zones1 and 2 .................................................................................. 616

12-7 Blocking Directional Comparison ............................................................................. 618

12-8 Directional Comparison Unblocking.......................................................................... 619

12-9 Direct Underreach.................................................................................................. 620

12-10 Permissive Underreach........................................................................................... 621

12-11 Single-Phase Comparison........................................................................................ 623

12-12 Distribution Circuit Protective Elements.................................................................... 624

12-13 Typical Transformer Relay Protection...................................................................... 627

12-14 Bus Differential Relay Protection............................................................................. 629

12-15 Pseudo Bus Differential Circuit................................................................................ 630

12-16 Typical Breaker Failure Relay Scheme..................................................................... 632

12-17 Coordination Conditions........................................................................................... 634

13-1 Linear Scale Analog Switchboard Voltmeters........................................................... 652

13-2 Nonlinear Scale Power Factor Meter....................................................................... 653

13-3 Multi-Function Meter .............................................................................................. 657

14-1 Substation Automation Architecture ......................................................................... 661

14-2 Substation Automation Data Acquisition and Control Elements................................... 662

15-1 Typical AC Auxiliary System Secondary Voltages.................................................... 675

15-2 Typical AC Auxiliary System................................................................................... 677

15-3 Typical DC Auxiliary System................................................................................... 684

15-4 Typical Battery Ground Detection System................................................................ 687

16-1 Pre-Engineered Metal Control Building..................................................................... 690

16-2 Typical Masonry Block Control Building................................................................... 691

16-3 Architecturally Pleasing Masonry Building................................................................ 691

16-4 Typical Relay/Control Panel Layout......................................................................... 693

16-5 19-Inch Rack-Mount Relay/Communications Equipment (PSI)................................... 693
Bulletin 1724E-300

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FIGURE TITLE 

17-1 Typical Carrier System............................................................................................ 701

17-2 Single-Frequency Resonant Tuning .......................................................................... 702

17-3 Double-Frequency Resonant Tuning......................................................................... 703

17-4 Wideband Tuning.................................................................................................... 704

17-5 6 GHz Microwave Terminal Mounted on Substation Box Structure ............................ 707

17-6 MAS Microwave Antenna on Substation Control House............................................ 708

17-7 OPGW Splice on Deadend Structure in Substation.................................................... 710

17-8 Fiber-Optic Multiplexers and Fiber-Optic Patch Panel............................................... 710

17-9 VSAT Installed in Electric Substation....................................................................... 713

19-1 DC High Potential Test, Typical Test Current vs. Time ............................................. 738

19-2 Steady Current vs. Voltage...................................................................................... 739

21-1 Substation Expansion............................................................................................... 759
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LIST OF TABLES

TABLE TITLE 2-1 Noise-Zone Classification......................................................................................... 44

2-2 Altitude Correction Factors for Substation Equipment................................................. 47

3-1 Substation Design Chronology................................................................................... 56

3-2 Typical Document Distribution List........................................................................... 99

4-1 Switching Scheme Cost Comparison........................................................................ 141

4-2 Apparatus Insulator BIL Ratings for Nominal System Voltages................................. 146

4-3 Altitude Correction Factors/BIL.............................................................................. 147

4-4 Typical Characteristics of Cap and Pin-Type Insulators............................................. 149

4-5 Typical Characteristics of Post-Type Insulators........................................................ 150

4-6 Minimum Quantity of Suspension Insulators............................................................ 153

4-7 Outdoor Electrical Substation Clearances................................................................. 154

4-8 Phase Spacing of Outdoor Air Switches................................................................... 155

4-9 Effects of Derating for 2400 Meters......................................................................... 156

4-10 Altitude Correction Factors/Current......................................................................... 161

4-11 NESC Conductor Wind and Ice Loads..................................................................... 165

4-12 Conductor Maximum Span and Deflection Multiplying Factors................................. 167

4-13 Ideal Locations for Couplers in Continuous Uniformly Loaded Rigid Conductors....... 170

4-14 ASA Schedule 40 Aluminum Pipe Conductors, Physical Properties........................... 172

4-15 NESC Conductor Loading Criteria ........................................................................... 178

5-1 Maximum Allowable Average Temperature of Cooling Air for Carrying Rated kVA.. 193

5-2 Rated kVA Correction Factors for Altitudes Greater Than 3300 ft (1000 m) ............... 193

5-3 Range of Voltage and Kilovolt-Ampere Ratings for Single-Phase Transformers,

833-8333 kVA........................................................................................................ 194

5-4 Range of Voltage and Kilovolt-Ampere Ratings for Three-Phase Transformers,

Without Load Tap Changing, 750-10 000 kVA......................................................... 195

5-5 Range of Voltage and Kilovolt-Ampere Ratings for Three-Phase Transformers

with Load Tap Changing, 3750-10 000 kVA ............................................................ 196

5-6 Range of Voltage and Kilovolt-Ampere Ratings for Three-Phase Transformers

With or Without Load Tap Changing, 12 000-60 000 kVA........................................ 197

5-7 Relationships of Nominal System Voltage to Maximum System Voltage and Basic

Lightning Impulse Insulation Levels (BIL) for Systems 765 kV and Below................ 198

5-8 High-Voltage Winding Insulation Levels of Single-Phase Transformers.................... 199

5-9 High-Voltage Winding Insulation Levels of Three-Phase Transformers ..................... 199

5-10 Minimum Insulation Levels at Neutral..................................................................... 200

5-11 BILs and Percentage Impedance Voltages at Self-Cooled (OA) Rating....................... 202

5-12 Dielectric Insulation Levels for Distribution Transformers and Class I Power

Transformers.......................................................................................................... 205

5-13 Dielectric Insulation for Class II Power Transformers............................................... 206

5-14 Alarm Limits for Transformer Cooling..................................................................... 209

5-15 Audible Sound Levels for Oil-Immersed Power Transformers................................... 213

5-16 Audible Sound Levels for Liquid-Immersed Distribution Transformers and

Network Transformers............................................................................................ 212

5-17 Audible Sound Levels for Dry-Type Transformers, 15 000-Volt Nominal System

Voltage and Below ................................................................................................. 212
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TABLE TITLE 

5-18 Guidelines for Specification of Dielectric Tests on Power Transformers Rated

345 kV and Below .................................................................................................. 215

5-19 Types of Circuit Breakers....................................................................................... 221

5-20 Preferred Rating for Indoor Circuit Breakers with Voltage Range Factor K = 1.0........ 227

5-21 Preferred Rating for Indoor Circuit Breakers with Voltage Range Factor K >1.0......... 229

5-22 Preferred Dielectric Withstand Ratings and External Insulation.................................. 231

5-23 Preferred Ratings for Outdoor Circuit Breakers 72.5 kV and Below, Including

Circuit Breakers Applied in Gas-Insulated Substations.............................................. 232

5-24 Preferred Ratings for Outdoor Circuit Breakers 121 kV and Above, Including

Circuit Breakers Applied in Gas-Insulated Substations.............................................. 233

5-25 Altitude Correction Factors (ACF) for Voltage and Current....................................... 234

5-26 Rated Control Voltages and Their Ranges for Circuit Breakers.................................. 240

5-27 Rated Insulation Levels of Metal-Clad Switchgear.................................................... 249

5-28 Range of Regulation vs. Rated Current for Single-Phase Step Regulators Rated

19.9 kV and Below ................................................................................................. 257

5-29 Range of Regulation vs. Rated Current for Three-Phase Step Regulators Rated

13.8 kV and Below ................................................................................................. 257

5-30 Preferred Ratings for Oil-Immersed Step-Voltage Regulators (Single-Phase) ............. 258

5-31 Preferred Ratings for Oil-Immersed Step-Voltage Regulators (Three-Phase).............. 259

5-32 Limits of Temperature Rise..................................................................................... 260

5-33 Dielectric Strength Correction Factors for Altitudes Greater than 3300 Feet

(1000 Meters)......................................................................................................... 260

5-34 Reduction Factors for Altitudes Greater Than 1000 m (3300 ft)................................. 261

5-35 Capacitor Unit Voltage and BIL Ratings .................................................................. 271

5-36 Switching Devices.................................................................................................. 271

5-37 Comparison of Operating Characteristics of Capacitor Controls................................. 277

5-38 Preferred Voltage Ratings for Station Class Outdoor Air Switches............................. 302

5-39 Preferred Switching Impulse Withstand Voltage for Station-Class Outdoor Air

Switches................................................................................................................ 303

5-40 Preferred Continuous and Withstand Currents for Station-Class Outdoor Air

Switches................................................................................................................ 304

5-41 Altitude Correction Factors for High-Voltage Air Switches....................................... 308

5-42 Switch Ratings and Required Tests.......................................................................... 309

5-43 Temperature Limitations for Air Switches................................................................ 311

5-44 Multiplying Factor (M) for Calculation of Electromagnetic Forces............................ 313

5-45 Terminal Loadings for High-Voltage Switches......................................................... 314

5-46 Station-Class Outdoor Air Switch—Pole Unit Dimensions........................................ 317

5-47 Station-Class Outdoor Air Switches Preferred Mounting Hole Spacing for 600-,

1200-, and 1600-Ampere Switches.......................................................................... 316

5-48 Phase Spacing and Ground Clearance for Station-Class Outdoor Air Switches and

Bus Supports.......................................................................................................... 318

5-49 Preferred Ratings for Indoor Air Switches................................................................ 319

5-50 Indoor Air Switches and Bus Support—Phase Spacing and Length of Break.............. 320

5-51 Grounding Switch Electrical Clearance.................................................................... 321

5-52 Arrester Voltage Ratings in Kilovolts....................................................................... 325

5-53 Pressure-Relief Test Currents for Station and Intermediate Arresters......................... 326

5-54 Protective Characteristics of Gapped Silicon-Carbide Station Arresters...................... 327

5-55 Protective Characteristics of Gapped Silicon-Carbide Intermediate Valve Arresters.... 328

5-56 Protective Characteristics of Gapped Silicon-Carbide Distribution Arresters.............. 329
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TABLE TITLE 

5-57 Metal Oxide Arrester Ratings in (kV) rms................................................................ 330

5-58 Metal Oxide Station- and Intermediate-Class Arrester Characteristic s........................ 331

5-59 Altitude Correction for Automatic Circuit Reclosers................................................. 361

5-60 Rated Maximum Voltage, Rated Continuous Current, Rated Interrupting Current,

Rated Impulse Withstand Voltage, and Performance Characteristics of Oil

Reclosers............................................................................................................... 365

5-61 Rated Maximum Voltage, Rated Continuous Current, Rated Interrupting Current,

Rated Impulse Withstand Voltage, and Performance Characteristics of Reclosers

with Vacuum Interrupters........................................................................................ 366

5-62 Rated Maximum Voltage, Rated Continuous Current, Rated Interrupting Current,

Rated Impulse Withstand Voltage and Performance Characteristics of Pad-Mounted,

Dry-Vault and Submersible Reclosers, and Non-Reclosing Fault Interrupters, All

with Vacuum Interrupters........................................................................................ 367

5-63 Continuous Current and Interrupting Current Ratings of Oil Reclosers....................... 368

5-64 Continuous Current and Interrupting Current Ratings of Reclosers with Vacuum

Interrupters ............................................................................................................ 369

5-65 Continuous Current and Interrupting Current Rating of Pad-Mounted, Dry-Vault,

and Submersible Reclosers, and Non-Reclosing Fault Interrupters, All with

Vacuum Interrupters............................................................................................... 370

5-66 Basic Impulse Insulation Levels and Dielectric Tests................................................ 378

5-67 Limits of Temperature Rise..................................................................................... 379

5-68 Standard Accuracy Class for Metering Service and Corresponding Limits of

Transformer Correction Factor (0.6 to 1.0 Power Factor (Lagging) of Metered

Load)..................................................................................................................... 380

5-69 Basic Impulse Insulation Levels and Dielectric Tests for Current Transformers

with the Same Dielectric Test Requirements as Outdoor Power Circuit Breakers........ 386

5-70 Ratings for Current Transformers with One or Two Ratios........................................ 386

5-71 Current Transformer Ratings, Multi-Ratio Type........................................................ 387

5-72 Standard Burdens for Current Transformers with 5 A Secondaries............................. 388

5-73 Ratings and Characteristics of Group 1 Voltage Transformers................................... 392

5-74 Ratings and Characteristics of Group 2 Voltage Transformers................................... 393

5-75 Ratings and Characteristics of Group 3 Outdoor Voltage Transformers...................... 394

5-76 Ratings and Characteristics of Group 4 Indoor Voltage Transformers........................ 395

5-77 Ratings and Characteristics of Group 5 Outdoor Voltage Transformers...................... 396

5-78 Standard Burdens for Voltage Transformers............................................................. 396

5-79 Voltage Ratings, Dielectric Strengths, Leakage Distances, and Marked Ratios

for CCs and CCVTs................................................................................................ 406

5-80 Burdens for Accuracy Rating................................................................................... 407

6-1 Rainfall Intensity and Conversion Factors................................................................ 416

6-2 Unified (ASTM) Soil Classification System............................................................. 420

6-3 Fence Posts for 2134-mm (7-Foot) Fence................................................................. 427

7-1 UBC Seismic Zone Factors..................................................................................... 437

7-2 Site Coefficient for Soil Characteristics.................................................................... 438

7-3 Structures—Type Factor ......................................................................................... 439

7-4 Summary of Mass and Deflection—Design Example ................................................ 450

7-5 Suggested Allowable Bolt Shear.............................................................................. 451
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TABLE TITLE 

8-1 Recommended Lateral Soil Pressure (R).................................................................. 472

8-2 Moment Coefficients............................................................................................... 472

8-3 Maximum Moment in kN-m for Augered Piers with 6 Straight Bars.......................... 474

8-4 Maximum Moment in kN-m for Augered Piers with 8 Straight Bars.......................... 475

8-5 Maximum Moment in Ft-KIPS for Augered Piers with 6 Straight Bars....................... 475

8-6 Maximum Moment in Ft-KIPS for Augered Piers with 8 Straight Bars....................... 475

9-1 Typical Values of Df............................................................................................... 534

9-2 Material Constants Data for Equation 9-10............................................................... 536

9-3 Material Constants Data for Equation 9-11............................................................... 537

9-4 Typical Surface Material Resistivities...................................................................... 546

10-1 Color Sequence ...................................................................................................... 565

10-2 Properties of Cable Insulating Materials................................................................... 566

11-1 DC Potentials of Various Buried Metals................................................................... 596

11-2 Soil Corrosiveness vs. Resistivity............................................................................. 598

17-1 Substation Communication Methods vs. Applications............................................... 699

18-1 Substation Inspection Technology Matrix................................................................. 724

19-1 Acceptance Test Requirements................................................................................ 735

19-2 Periodic Test Requirements..................................................................................... 736

19-3 Acceptable Power Factor Values............................................................................. 738

19-4 Typical Insulation Resistance Values....................................................................... 740

20-1 Recommendations for Periodic Maintenance ............................................................ 748

Index:

 DESIGN, SYSTEM:

 Design Guide for Rural Substations

 MATERIALS AND EQUIPMENT:

 Design Guide for Rural Substations

 OPERATIONS AND MAINTENANCE:

 Design Guide for Rural Substations

 SUBSTATIONS:

 Design Guide for Rural Substations
Bulletin 1724E-300

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ABBREVIATIONS AND ACRONYMS

" Inches

% Percentage

ρ Resistivity

°C Degrees Celsius

°F Degrees Fahrenheit

μs Microseconds

2D Two Dimensional

3D Three Dimensional

A Amperes

AASHTO American Association of State Highway and Transportation Officials

AC Alternating Current

ACI American Concrete Institute

ACR Automatic Circuit Recloser

ACSR Aluminum Conductor Steel Reinforced

ADSC Association of Drilled Shaft Contractors

ADSS All-Dielectric Self-Supporting

AEIC Association of Edison Illuminating Companies

AEP American Electric Power

AFOW Arrester Front of Wave

AIEE American Institute of Electrical Engineers

AISC American Institute of Steel Construction

ANSI American National Standards Institute

ASCE American Society of Civil Engineers

ASD Allowable Stress Design

ASTM American Society for Testing and Materials

ASYM Asymmetrical

ATM Asynchronous Transfer Mode

AWG American Wire Gage

BIL Basic Impulse Insulation Level

BOCA Building Officials and Code Administration

BSL Basic Switching Impulse Insulation Level

CADD –Computer-Aided Design and Drafting

CC Coupling Capacitor

CCVT Coupling Capacitor Voltage Transformer

CFR Code of Federal Regulations

cm Centimeter

COG Coefficient of Grounding

CPM Critical Path Method

Cpt Cap and Pin Type

CPU Central Processing Unit

CSMA/CD Carrier Sense Multiple Access with Collision Detection

CRN Cooperative Research Network

CT Center Tap; Current Transformer

Cu Copper

CVT Capacitor Voltage Transformer

CWW Chopped Wave Withstand

dB Decibels
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dBA Decibels above 1 ampere

DC Direct Current

DCE Data Communications Equipment

Dist. Distribution

DOT Department of Transportation

DS1 Digital Signal Level 1

DTE Data Terminating Equipment

DTM Digital Terrain Model

DV Discharge Voltage

E Modulus of Elasticity

EA Environmental Assessment

ECSA Exchange Carrier Standards Association

EHV Extra High Voltage

EMF Electromagnetic Force; Electromotive Force

EMTP Electromagnetic Transient Program Analysis

EPA Environmental Protection Agency

EPR Ethylene Propylene Rubber

EPRI Electric Power Research Institute

ER Environmental Report

ESD Electric Staff Division

f Frequency

FA Forced Air

FAA Federal Aviation Administration

FCC Federal Communications Commission

FDDI Fiber Distributed Data Interface

FHWA Federal Highway Administration

FM Frequency Modulation

FOW Front of Wave

FSK Frequency Shift Keying

ft Feet

Fv Allowable Shear Stress

GFI Ground Fault Interrupting

GFR General Field Representative

GHz Gigahertz (1,000,000,000 hertz or cycles per second)

GIS Gas-Insulated Substations

gpm Grams per minute

GPR Ground Potential Rise

GRD Ground

HMI Human–Machine Interface

hr Hour

HUD Department of Housing and Urban Development

HV High Voltage

HVAC Heating, Ventilating, and Air Conditioning

Hz Hertz (cycles per second)

I.D. Inside Diameter

ICBO International Conference of Building Officials

ICEA Insulated Cable Engineers Association

IEC International Electrotechnical Association

IED Intelligent Electronic Device

IEEE Institute of Electrical and Electronics Engineers
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IES Illuminating Engineering Society

in. Inch

IPS International Pipe Standard

IR Insulation Resistance

ISO International Organization for Standardization

J Joule

K Rated Voltage Range Factor

kA Kiloamperes (1,000 amperes)

kcmil Kilocircular mils (1,000 circular mils)

kg Kilogram (1,000 grams)

kHz Kilohertz (1,000 hertz or cycles per second)

km Kilometers (1,000 meters or 1,608 feet)

km/h Kilometers per hour

kN Kilonewtons

kNm Kilonewton meters

kPa Kilopascals (1,000 Pascals)

ksi KIP (1000lbs) per square inch

kV Kilovolt (1,000 volts)

kVA Kilovolt-amperes (1,000 volt-amperes)

kVAR Kilovolt-amperes reactive (1,000 volt-amperes reactive)

kWh Kilowatt-hour

LAN Local Area Network

lb Pound

lbs Pounds

lbs/ft Pounds per foot

L/C

LCD

Inductance/Capacitance

Liquid Crystal Display

LPL Lightning Protective Level

LRFD Load and Resistance Factor Design

LTC Load Tap Changer

LTU Line Tuner Unit

LV Low voltage

m Meter(s)

m

2

Square meter

mA Milliamperes (0.001 ampere)

MAS Multiple Address System

Mbps megabits per second (1,000,000 bits per second)

MCOV Maximum Continuous Operating Voltage

McTRANS Center Center for Microcomputers in Transportation

MHz Megahertz (1,000,000 hertz or cycles per second)

mil One Thousandth of an Inch

mm Millimeter (0.001 meter)

MOV Motor-Operated Valve

mph Miles per hour

mV Millivolt

MVA Megavolt-amperes (1,000,000 volt-amperes)

MVAR Megavolt-amperes reactive (1,000,000 volt-amperes)

MW Megawatt (1,000,000 watts)

N Newton

N/m Newtons per meter
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NACE Formerly known as “National Association of Corrosion Engineers”, now

known as “NACE International – The Corrosion Society”

NEC National Electrical Code

NEMA National Electrical Manufacturers Association

NEPA National Environmental Policy Act of 1969

NESC National Electrical Safety Code

NETA National Electrical Testing Association

NFPA National Fire Protection Association

NI-CAD Nickel Cadmium

NLTC No-Load Tap Change

NRECA National Rural Electric Cooperative Association

O & M Operations and Maintenance

O.I. Oxygen Index

OA Self-cooled

OA/FA Self-cooled and assisted by forced air for one stage

OA/FA/FA Self-cooled and assisted by forced air for two stages

OA/FA/FOA Self-cooled and assisted by forced air and forced oil

OA/FOA Self-cooled and assisted by forced oil

OA/FOA/FOA Self-cooled and assisted by forced air and forced oil for two stages

OC-1 SONET optical carrier 1 (51.83 Mbps)

OC-3 SONET optical carrier 3 (155.52 Mbps)

OC-12 SONET optical carrier 12 (622.08 Mbps)

OC-48 SONET optical carrier 48 (2488.32 Mbps)

O.D. Outside Diameter

OEM Original Equipment Manufacturer

OLF Overload factor

OPGW Optical Ground Wire

OSHA Occupational Safety and Health Administration

OSI Open Systems Interconnection

PC Personal computer

PCA Portland Cement Association

PCB Polychlorinated biphenyls

pcf Pounds per cubic foot

PCM Pulse Code Modulation

PE Polyethylene

PF Power Factor

pH Logarithmic measure of hydrogen ion concentration

PILC Paper Insulated Lead Cable

PLC Power line Carrier; Programmable Logic Controller

PO Purchase Order

psf Pounds per square foot

psi Pounds per square inch

PT Potential Transformer

PVC Polyvinyl Chloride

Pw Wind pressure

RAM Random Access Memory

RCF Ratio Correction Factor

REA Rural Electrification Administration

RF Rating Factor; Radio Frequency

rms Root Mean Square
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RPM Revolutions per Minute

RQD Rock Quality Designation

RTU Remote Terminal Unit

RUS Rural Utilities Service

Rw Structure-type factor

S.O. Sparkover

S.S. Switching Surge

SBCC Southern Building Code Congress

SCADA Supervisory Control and Data Acquisition

SF

6 Sulfur Hexaflouride

SOE Sequence of Events

SONET Synchronous Optical Network

SPCC Spill Prevention Control and Countermeasure

SPL Arrester Surge Protective Level

SSB Single Sideband

SSPC Steel Structures Painting Council

Std. Standard

Sym Symmetrical

TCF Transformer Correction Factor

TCP/IP Transport Control Protocol/Internet Protocol

TDM Time-Division Multiplexed

TFOW Transformer Front of Wave

TIN Triangulated Irregular Network

TNA Transient Network Analysis

T.O.C. Top Of Concrete

TOV Temporary Overvoltage

UBC Uniform Building Code

UCA Utility Communications Architecture

UL Underwriters Laboratories

USDA United States Department of Agriculture

USWG USA Steel Wire Gage

UTP Unshielded Twisted Pair V Volts

VA Volt-amperes

VAC Volts Alternating Current

VAR Volt-amperes reactive

VDC Volts Direct Current

VSAT Very Small Aperture Terminal

VSD Variable-Speed Drive

VT Voltage Transformer

WAN Wide Area Network

XLPE Cross-Linked Polyethylene

ZPA Zero Period Acceleration
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(BLANK PAGE)
Bulletin 1724E-300

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CHAPTER 1

INTRODUCTION

1.1 PREFACE

This bulletin provides design guidance for the increasing numbers of substations necessary to meet the

increasing electrical demands in areas served by Rural Utilities Service borrowers (here and after called

cooperatives). This guide bulletin is intended for the benefit of cooperatives, their consulting and staff

engineers, and others interested in rural substation design and construction concerns and considerations.

Substations should be designed, constructed, and operated to meet customers’ needs at the lowest possible

cost commensurate with the quality of service desired. The typical system may include substations for

voltage transformation, sectionalizing, distribution, and metering a number of times between generation

and utilization.

1.2 PURPOSE AND SCOPE

This bulletin covers rural transmission and distribution with air-insulated, outdoor substations 345 kV

(phase-to-phase) and below.

Possible design responsibilities of the engineer are covered, including preparation of construction

drawings, material, equipment and labor specifications, and any other engineering design services that

may be required.

The engineering function is generally more than furnishing of design and specifications. Recognition of

this function becomes especially important when a cooperative employs an engineering firm to

supplement its staff. (See U.S. Code of Federal Regulations, Title 7, Part 1724 (7 CFR 1724), “Electric

Engineering, Architectural Services and Design Policies and Procedures.”) The contract between a

cooperative and an engineering firm should be clear in its definition of the engineering functions to be

performed. Within this bulletin, it should be understood that the term “engineer” could mean either a

cooperative’s staff engineer(s) or a consultant’s engineer(s).

The engineer needs to use these guidelines together with experience and knowledge. A list of references

at the end of most chapters will aid in the search for more detailed information. It is recommended that,

where other resources are referenced, such as those of ANSI, IEEE, RUS, and ASTM, the substation

designer obtain and become familiar with the appropriate document.

Use of this publication for substation design will usually result in an economical approach from a system

standpoint. This should eventually result in the evolution of standard designs for a given system.

Standardization is a desirable and achievable objective that should be pursued.

Technical advances and changes in codes and standards that could cause some of the material in this

bulletin to become obsolete continue to proliferate in the electric power industry. Users, therefore, need

to continue their own efforts to stay up to date with the changing technologies.

1.3 RELATIONSHIP OF SUBSTATION TO OVERALL POWER SYSTEM

A substation is part of a system and not an entity to itself. Normally, a power system is designed so that
Bulletin 1724E-300

Page 38

An example of an outage consideration for a

substation would include a transmission switching

station that operates with a simple main bus. An

outage of the bus results in a complete interruption of power through the substation. The

engineer will need to consider other equipment in

the substation, such as a transfer bus or different

multi-bus arrangement. The engineer should also

evaluate the adjacent system to determine if the

load can be diverted around the substation for

outages to minimize the equipment that is

installed in a substation.

the effects of an outage (caused by the failure of a single component such as a transformer, transmission

line, or distribution line) will result in minimal interruption of service and affect the fewest customers

possible.

Failure of one component in a system often forces a greater than normal load to be carried by other

components of the system. Such contingencies are normally planned for and incorporated into design

criteria.

When evaluating the switching arrangement for a

substation, an engineer needs to be aware of the

system configuration of which the substation will

be a part. System contingency arrangements need

to permit the outage of components in a

substation for maintenance and unscheduled

outages.

Most substations are designed to operate unattended. Remote indication, control, metering,

and methods of communication are often

provided so that systems and portions of systems

can be monitored from a central point.

1.4 IMPORTANCE OF ADEQUATE SUBSTATION PLANNING AND ENGINEERING

(See Bulletins 1724D-101A, “Electric System Long-Range Planning Guide,” and 1724D-101B, “System

Planning Guide, Construction Work Plans.”)

Substation planning considers the location, size, voltage, sources, loads, and ultimate function of a

substation. If adequate planning is not followed, a substation may require unnecessary and costly

modification.

The engineer’s detailed work requires use of valid requirements and criteria, appropriate guidelines, and

engineer’s own expertise in order to provide construction drawings and associated documents appropriate

for needed system improvements. The engineer’s ability to meld the diverse constraints into an

acceptable design is essential.

During the design phase, the engineer should avoid personal preferences in solving technical problems

that diverge from the use of nationally accepted standards, Rural Utilities Service (RUS) standards, or the

concept of the cooperative’s standard designs.

Adequate engineering design provides direction for construction, procurement of material and equipment,

and future maintenance requirements while taking into account environmental, safety, and reliability

considerations.

1.5 TYPES OF SUBSTATIONS

1.5 .1 General

Substations may be categorized as distribution substations, transmission substations, switching

substations, or any combination thereof.
Bulletin 1724E-300

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A good example of confusion over the definition

of terms that can be experienced exists for the

term “outage.” An industrial firm with a

variable-speed drive (VSD) required a minimum

number of outages on the incoming feeder since

any outage resulted in the drive’s going down,

several hours’ delay in the restart, and possible

environmental consequences during the outage.

The utility reviewed its own outage criteria and

determined it met the customer’s requirements.

After installation, the customer complained

about the large number outages forcing the VSD

motor to de-energize. Further discussion

revealed the customer’s definition of outage was

any voltage drop of 20 percent or more for more

than three cycles. The utility’s definition of

outage was any discontinuance of service after

all reclosing of a feeder failed. Differing usage

of common terms resulted in unacceptable

service to the customer, requiring modifications

to the installation.

One design tendency is to reduce costs by reducing the number of substations and taking advantage of

economies of scale. Conversely, practical system design and reliability considerations tend to include

many substations. One function of system studies is to balance these two viewpoints.

1.5.2 Distribution Substations

A distribution substation is a combination of

switching, controlling, and voltage step-down

equipment arranged to reduce subtransmission voltage

to primary distribution voltage for residential, farm,

commercial, and industrial loads.

Rural distribution substation capacities vary.

Substations generally include one l.5 MVA to three

5 MVA transformers. These substations may be

supplied radially, tapped from a subtransmission line,

or may have two sources of supply. Most

cooperatives’ substations have 12,470Y/7200-volt or

24,490Y/14,400-volt distribution circuits.

A special class of distribution substation would

include a dedicated customer substation. This

substation would be similar to a distribution substation

except that all of its capacity would be reserved for the

service of one customer. The secondary voltages of a

dedicated substation would also be modified to match

special requirements of the customer. Coordination

with the customer is of primary importance in

determining the technical requirements. Confirmation of the technical terms being used is likely to be

required since electrical engineers in differing industries may use the same terms to describe similar, yet

technically different, criteria.

1.5.3 Transmission Substations

A transmission substation is a combination of switching, controlling, and voltage step-down equipment

arranged to reduce transmission voltage to subtransmission voltage for distribution of electrical energy to

distribution substations. Transmission substations frequently have two or more large transformers.

Transmission substations function as bulk power distribution centers, and their importance in the system

often justifies bus and switching arrangements that are much more elaborate than distribution substations.

1.5.4 Switching Substations

A switching substation is a combination of switching and controlling equipment arranged to provide

circuit protection and system switching flexibility.

Switching stations are becoming common on cooperatives’ transmission systems. Flexible switching

arrangements in a transmission network can aid in maintaining reliable service under certain abnormal or

maintenance conditions.
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1.6 REFERENCES

7 CFR 1724, “Electric Engineering, Architectural Services and Design Policies and Procedures.”

RUS Bulletin 1724D-101A, “Electric System Long-Range Planning Guide.”

RUS Bulletin 1724D-101B, “System Planning Guide, Construction Work Plans.”
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Significant considerations for

future construction are the outage

requirements when equipment is

added. These requirements should

be considered with the utility’s

ability to serve the load during any

outage.

CHAPTER 2

GENERAL DESIGN CONSIDERATIONS

2.1 INITIAL AND ULTIMATE REQUIREMENTS

Cooperatives should consider both short- and long-range plans in the development of their systems.

Timely development of plans is not only essential for the physical and financial integrity of electrical

systems, it is also essential in supplying customers with adequate service.

The long-range plan identifies the requirements of a

substation not only for its initial use but also for some years

in the future. Consider ultimate requirements during the

initial design. Make economic comparisons to discover what

provisions are necessary for ease of addition.

Remember that development plans embrace philosophies of

equipment and system operation and protection before

construction is started. Changes in the cooperative’s standard design philosophies should be reviewed by

the personnel who design, operate, and maintain the proposed equipment. Departures from standard

designs could jeopardize the operation of the system.

Use the Substation Design Summary in Appendix B to Chapter 3 to summarize basic design data.

2.2 SITE CONSIDERATIONS

Two of the most critical factors in the design of a substation are its location and siting. Failure to

carefully consider these factors can result in excessive investment in the number of substations and

associated transmission and distribution facilities.

It is becoming increasingly important to perform initial site investigations prior to the procurement of

property. Previous uses of a property might render it very costly to use as a substation site.

Such previous uses might include its use as a dumping ground where buried materials or toxic waste has

to be removed prior to any grading or installation of foundations.

The following factors should be evaluated when selecting a substation site:

a. Location of present and future load center

b. Location of existing and future sources of power

c. Availability of suitable right-of-way and access to site by overhead or underground

transmission and distribution circuits

d. Alternative land use considerations

e. Location of existing distribution lines

f. Nearness to all-weather highway and railroad siding, accessibility to heavy equipment under all

weather conditions, and access roads into the site

g. Possible objections regarding appearance, noise, or electrical effects

h. Site maintenance requirements including equipment repair, watering, mowing, landscaping,

storage, and painting

i. Possible objections regarding present and future impact on other private or public facilities
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j. Soil resistivity

k. Drainage and soil conditions

l. Cost of earth removal, earth addition, and earthmoving

m. Atmospheric conditions: salt and industrial contamination

n. Cost of cleanup for contaminated soils or buried materials

o. Space for future as well as present use

p. Land title limitations, zoning, and ordinance restrictions

q. General topographical features of site and immediately contiguous area; avoidance of

earthquake fault lines, floodplains, wetlands, and prime or unique farmlands where possible

r. Public safety

s. Public concern; avoidance of schools, daycare centers, and playgrounds

t. Security from theft, vandalism, damage, sabotage, and vagaries of weather

u. Total cost including transmission and distribution lines with due consideration of

environmental factors

v. Threatened and endangered species and their critical habitat

w. Cultural resources

x. Possible adverse effects on neighboring communications facilities

Choose a substation location that precludes placing any communications facilities within the substation

300 V peak ground potential rise (GPR) zone of influence. See ANSI/IEEE Std. 367-1987,

“Recommended Practice for Determining the Electric Power Station Ground Potential Rise and Induced

Voltage from a Power Fault,” and ANSI/IEEE Std. 487-1992, “Communication Facilities Serving Electric

Power Stations, Guide for the Protection of Wire Lines.”

2.3 ENVIRONMENTAL CONSIDERATIONS

2.3.1 General

2.3.1.1 RUS Environmental Policies and Procedures, 7 CFR 1794: This Regulation specifies RUS

environmental requirements pursuant to the implementation of the National Environmental Policy Act of

1969 and Council on Environmental Quality Regulations. It also references additional authorities,

directives, and instructions relevant to protection of the environment.

As a general rule, substations requiring greater than 2 hectares (5 acres) of new physical disturbance need

an Environmental Assessment (EA), while those below generally require an Environmental Report (ER)

(see RUS Bulletins 1794A-600, “Guide for Preparing an Environmental Report for Categorically

Excluded Projects” and 1794-601, “Guide for Preparing an Environmental Report for Electric Projects

Requiring an Environmental Assessment”).

2.3.1.2 Appearance: Appearance is becoming increasingly important to the public. In some areas,

zoning regulations and suggestions by civic organizations often mean screening, low-profile designs, or

other measures to improve appearance. The absence of such direct influence in rural areas should not be

a reason for not considering newer design practices. The general trend is to locate substations in a way

that they are not strikingly visible to the public. A substation set back from a heavily traveled road may

require little or no architectural treatment to be acceptable.

Coordinate engineering of transmission, distribution, and substation facilities to develop the least overall

objectionable layout. Consider underground distribution circuit exits for special applications.
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The silhouette of a substation may be reduced in several ways, including the use of solid-shape structural

sections. Lowering of the substation profile may also be accomplished by means other than underground

circuits although this approach may necessitate a larger surface area, resulting in larger site requirements.

Lower profile designs for substation high-voltage equipment may be cost-effective in design and in

reducing the profile that the substation projects.

Landscaping or architectural screening may offer effective means to blend a substation into the

surrounding environment. Landscaping has typically included the use of trees, bushes, and the like to

screen the substation. In some cases, masonry walls or enclosures have been necessary to meet permitting

requirements in special use areas. Some sites may provide a natural screening with either vegetation or

natural barriers.

Generally, it is better to use complementary rather than contrasting colors. Sometimes, coloring can be

used to blend substation equipment into the background.

Outdoor lighting of the substation site may have an effect on the acceptance of the substation in a

community. Lighting is typically a means to deter vandalism. It also provides safety for line crews who

may be performing maintenance at night. A means of switching off a portion of the lights at night to

provide reduced lighting may make the site more acceptable to the community.

2.3.1.3 Public Safety: Substations should be safe for people who may have occasion to be near them.

The primary means of ensuring public safety at substations is by the erection of a suitable barrier such as

a metal fence. Unless local restrictions are more conservative, the fence needs to meet the minimum

requirements specified in the National Electrical Safety Code and IEEE Std. 1119, “IEEE Guide for

Fence Safety Clearances.” (RUS recommends 8 feet for the fence height: 7 feet of fabric and a 1-foot

extension of barbed wire.) Metal fences have to be properly grounded; grounding of fences is covered in

Chapter 9. Material and specification of fences is covered in Chapter 6, Section 6.9.

Additional means of protecting the public are provided through adequate design of all facilities inside the

fence and the addition of a peripheral ground outside the fence. Protection that alleviates possible

potential differences is discussed in Chapter 9.

Appropriate warning signs should be posted on the substation’s peripheral barrier fence. The engineer

should specify their location and design. Substations, no matter how small, should have one sign per side,

as a minimum. For each substation site, assess whether standard signs are sufficient. Special bilingual

signs may be advisable for some areas. Additional signs, such as “No Trespassing,” may be advisable in

some areas. See ANSI Std. Z535.2, “Environmental and Facility Safety Signs,” for further information.

2.3.1.4 Audible Noise: Sources of audible noise within a substation include transformers, voltage

regulators, circuit breakers, and other intermittent noise generators. Among the sources, transformers

have the greatest potential for producing objectionable noise. The design engineer should consider

audible noise reference documents and regulations.

Corona, which is localized incomplete dielectric failure, causes a hissing sound. Corona noise occurring

at voltages of 230 kV and below is seldom serious. Corona noise is usually kept to a tolerable level if

guidelines for minimizing electrical effects are followed. Design for 345 kV systems will normally

require extra-high-voltage (EHV) connectors and fittings or corona shields to reduce the amount of noise

from corona to tolerable levels.
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The U.S. Environmental Protection Agency (EPA) has published “Information on Levels of

Environmental Noise Requisite to Protect Public Health and Welfare with an Adequate Margin of Safety”

(Report Number 550/9-74-004), and “Public Health and Welfare Criteria for Noise” (Report Number

550/9-73-002). Several state and local noise ordinances limit noise at the property line. Table 2-1 lists

guidelines for considering noise in land-use planning and control. The reaction to noise can be

subjective, so each substation situation should be analyzed separately.

Table 2-1: Noise-Zone Classification.

Ref. Federal Interagency Committee on Urban Noise, 1980, p. 5.

Noise Descriptor

Noise

Zone

Noise

Exposure

Class

DNL

Day-Night

Average

Sound Level

Leq (hour)

Equivalent

Sound level

NEF

Noise Exposure

Forecast

HUD Noise

Standards

A Minimal

Exposure

Not Exceeding

55

Not

Exceeding

55

Not Exceeding

20

B Moderate

Exposure

Above 55a But

Not Exceeding

65

Above 55

But

Not

Exceeding

65

Above 25 But

Not Exceeding

30

Acceptable

C-1

Above 65 But

Not Exceeding

70

Above 65

But Not

Exceeding

70

Above 30 But

Not Exceeding

35

C-2

Significant

Exposure Above 70 But

Not Exceeding

75

Above 70

But

Not

Exceeding

75

Above 35 But

Not Exceeding

40

Normally

Unacceptable

D-1

Above 75 But

Not Exceeding

80

Above 75

But Not

Exceeding

80

Not Exceeding

45

D-2

Above 80 But

Not Exceeding

85

Above 80

But

Not

Exceeding

85

Above 45 But

Not Exceeding

50

D-3

Severe

Exposure

Above 85 Above 85 Above 50

Unacceptable

a HUD, DOT, and EPA recognize Ldn = 55 dB as a goal for outdoor sites in residential areas in protecting the public

health and welfare with an adequate margin of safety.

However, it is not a regulatory goal. It is a level defined by a negotiated scientific consensus without concern for

economic and technological feasibility or the needs and desires of any particular community.

See Chapter 5, Section 5.2.12, for more information.

2.3.1.4.1 Site Selection: If the substation has to be located in or near a residential area, select a site

with the greatest distance from nearby residences, and, if possible, avoid a direct line of sight with them.
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A site with natural barriers such as earth mounds or shrubbery is desirable since such barriers can help

reduce the psychological impact of a new installation.

2.3.1.4.2 Layout Design: Good practice for noise control is to locate transformers the maximum

possible distance from the substation fence. Once a transformer is located, its noise level at any distance

can be estimated by using standard formula s. See IEEE Std. 1127, “IEEE Guide for the Design,

Construction, and Operation of Electric Power Substations for Community Acceptance and

EnvironmentalCompatibility,” for formulas that may be used. If noise is anticipated to be a problem,

reduced sound levels are available from the transformer manufacturer or the equipment layout should be

arranged to permit the installation of a sound barrier. Anticipated future requirements should also be

considered since additional transformers will increase the noise level.

2.3.1.4.3 Level: As a general rule, substation noise will not be a problem if, when combined with

ambient noise, it is less than 5 dBA above the ambient noise level. It may be desirable to measure the

ambient noise levels at locations of concern. Measurements should be taken during the quietest periods,

approximately midnight to 4 a.m. Calculation of the resultant sound level will then indicate whether

further study is required. The references at the end of this chapter suggest methods to rigorously address

noise problems.

2.3.1.4.4 Transformers: Chapter 5, Section 5.2, “Power Transformers” provides additional guidelines.

2.3.1.5 Electrostatic and Electromagnetic Effects: Consideration should be given to preventing radio

and television interference that could result from visible corona. Significant corona could be caused by

energized parts having small radii or from small-diameter conductors, particularly when conductive

climatic conditions prevail. Experience has shown, though, that conductor fittings and energized parts

other than conductors do not produce serious corona at phase-to-phase voltages of 230 kV and below. At

345 kV, electrical voltage gradients are such that corona shields and connectors designed to mitigate

corona should be used.

It is necessary, however, to consider the size of conductors. Chapter 4, “Physical Layout,” provides

guidelines for fault and load-carrying conductors. Connections to equipment such as voltage transformers

and coupling capacitors should not be sized from a current-carrying standpoint only. From a corona

standpoint, conductors should not be smaller than 3/0 at 230 kV or 1/0 at 161 kV and 138 kV. At 345 kV,

equipment jumpers should consist of bundled conductors.

2.3.1.6 Effluent: 40 CFR 110 and 112 provide regulations to eliminate the pollution of navigable

waterways. The essence of these regulations is that, upon the failure of a container filled with a pollutant,

such as oil in a transformer or oil circuit breaker, no harmful quantity of such pollutant (oil) may be

allowed to enter a navigable waterway. Absolute prevention and containment of oil spills is not required

by the regulations; however, the discharge of harmful quantities of pollutants into navigable waterways is

prohibited. The regulations and interpretations thereof are dynamic. It is necessary to have a Spill

Prevention Control and Countermeasures (SPCC) plan of action for disposing of effluent, should spills or

leaks occur. Some oil pollution prevention measures are described in Chapter 8 and in RUS Bulletin

1724E-302, “Design Guide for Oil Spill Prevention and Control at Substations.” If more than 5.0 acres of

land will be disturbed during construction, a stormwater discharge permit has to be obtained from the

appropriate state agency prior to the start of construction. See the above-mentioned CFR regulations and

IEEE Std. 980, “IEEE Guide for Containment and Control of Oil Spills in Substations,” for assistance in

determining the appropriateness of in-place structures and items to be included in an SPCC plan.
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The use of polychlorinated biphenyls (PCBs) as an insulation medium in liquid-filled transformers and

capacitors has been discontinued. This type of impregnant has been phased out, because of its resistance

to biodegradation, in favor of materials potentially less harmful to the environment.

2.3.2 Weather

2.3.2.1 General: As dependence on the use of electricity grows, it is increasingly important that

substations operate more reliably in extremes of weather than in the past.

2.3.2.2 Temperature : It is necessary to design a substation for the extreme temperatures expected.

Extreme temperatures could affect circuit breakers, relay protection, or the bus.

2.3.2.3 Wind: As a minimum, substations should be resistant to wind velocities as shown in

Figure 2-1. Chapter 4, “Physical Layout,” and Chapter 7, “Structures,” provide specific guidelines on

design. Local conditions may dictate more stringent wind designs.

2.3.2.4 Ice: A substation should continue to operate despite ice accumulation. Generally, consensus

equipment standards specify ice loadings for both electrical and mechanical withstands. The complete

substation assembly should also be undamaged by ice accumulation. From the ice accumulation history

for a given substation’s location, the engineer can judge whether more severe loadings than consensus

equipment standards are necessary. Additional viewpoints on ice loading are provided in Chapter 4,

“Physical Layout,” and Chapter 7, “Structures.”

2.3.2.5 Rain: A substation should be designed to be operable under predictable conditions of rainfall.

Additionally, it is desirable that substation drainage be sufficient enough to exhibit little standing water

within a few hours after a heavy rainfall. See Chapter 6, “Site Design,” for guidelines.

2.3.2.6 Snow: Snow introduces an extremely variable hazard to substations because of uncertainties in

drifting and accumulation. The substation has to be impervious to snow damage, and consideration needs

to be given to snow accumulation and the maintenance of clearances. The engineer should seek local data

on this weather variable.

2.3.2.7 Electrical Storms: The two measures normally employed for substation lightning protection

are surge arresters and shielding. Application guidelines for surge arresters are included in Chapters 4

and 5. Surge arresters provide little protection against direct strokes. Shielding is provided by overhead

wires, masts that are extensions of structures, or independent masts as covered in Chapter 4. A

combination of surge arresters and shielding will reduce the probability of damage from lightning.

2.3.2.8 Humidity: Consideration should be given to installation of differential thermostat-controlled

heating in outdoor cabinets such as circuit breaker control cabinets where condensation could be a

problem. In areas where fog occurs often, and particularly where airborne contamination exists, frequent

insulator flashovers may occur. Methods of reducing flashovers include the application of special

insulation and insulator cleaning.

2.3.3 Altitude

Equipment that depends on air for its insulating and cooling medium will have a higher temperature rise

and a lower dielectric strength when operated at higher altitudes; see ANSI Std. C37.30, “Standard

Definitions and Requirements for High-Voltage Air Switches, Insulators, and Bus Supports.”
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Surge arresters are designed for satisfactory operation at elevations up to a limit specified by the

manufacturer. Applications above this limit are considered special, and the manufacturer should be

consulted for a recommendation.

Dielectric strength of air, current ratings of conductors operated in air, and ambient temperatures should

be corrected for altitude variation and be multiplied by the factors shown in Columns “A” and “B” of

Table 2-2.

Table 2-2: Altitude Correction Factors for Substation Equipment.

Ref. ANSI/IEEE Std. C37.30-1992, Table 1, Copyright © 1992. IEEE. All Rights Reserved.

Altitude Correction Factor to

Altitude Be Applied to:

A B C

Feet Meters

Dielectric

Strength

Current

Rating

Ambient

Temperatures

3300 1000 1.00 1.00 1.00

4000 1200 0.98 0.995 0.992

5000 1500 0.95 0.99 0.980

6000 1800 0.92 0.985 0.968

7000 2100 0.89 0.98 0.956

8000 2400 0.86 0.97 0.944

9000 2700 0.83 0.965 0.932

10000 3000 0.80 0.96 0.920

12000 3600 0.75 0.95 0.896

14000 4200 0.70 0.935 0.872

2.3.4 Earthquakes

Substations subjected to intense earthquakes will most likely be damaged; however, seismic design

practices can minimize the damage. Although some substation equipment is inherently shock resistant,

the foundations, structures, equipment anchors, insulation, and conductors may not be. Designs that

minimize damage should be utilized in high seismic areas. Consideration should be given not only to

replacement costs but also to lead times for delivery of replacement equipment.

IEEE Std. C57.114, “IEEE Seismic Guide for Power Transformers and Reactors,” provides

recommendations as to design considerations for the installation of transformers and reactors when

seismic activity is likely.

When substations will be constructed with Federal financing assistance, RUS require substation control

buildings to meet the seismic provisions found in 7 CFR 1792, Subpart C.

Seismic loads are governed by the region of the country in which they occur. Figure 2-2 identifies the

susceptibility of different areas of the country, with the higher numbered areas being more susceptible.

Further discussion concerning seismic loads is explained in section 7.4.7 of this bulletin.
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Figure 2-1: Basic Wind Speed. Ref. ANSI/ASCE Std. 7-95, Figure 6-1.

Reproduced with permission of the American Society of Civil Engineers, copyright © 1989.
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The seismic zone map from the Uniform Building Code has been included for reference. See Figure 2-2.

Figure 2-2: Seismic Zone Map of the United States. Ref. Uniform Building Code—1997,

Figure 16-2. Reproduced from the 1997 edition of the Uniform Building CodeTM, copyright © 1997,

with permission of the publisher, the International Conference of Building Officials.

2.3.5 Other Considerations

2.3.5.1 Wildlife and Livestock: A substation should be protected from wildlife and livestock. The

primary means of protection is the perimeter barrier. This is generally a chain link fence that keeps out

larger animals. It may also be necessary to have rodent and/or reptile barriers. It is recommended that all

substation materials be non-nutrients, since impregnable barriers would be too difficult to attain. Insect

screening should be applied where local experience indicates it is beneficial. Avoiding attractive nesting

and perching sites usually minimizes bird damage. Adequate clearances should be provided to prevent

electrocution of local bird species. For measures to prevent and mitigate damage from animals, insects,

birds, and reptiles, see the Cooperative Research Network’s (CRN’s) manual on Animal-Caused Outages.

2.3.5.2 Airborne Foreign Material: Airborne seeds, leaves, debris, dust, and salts that are local

phenomena could be a problem. Buildup could occur that would compromise electrical insulation or

interfere with cooling. Appropriate prevention measures should be included in the design of a substation

expected to be exposed to such contamination.
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2.4 INTERFACING CONSIDERATIONS

Substations interface with roadways, area drainage, communications systems, and electric power lines.

Sufficient lead time has to be allowed to coordinate activities with public agencies for roadway access and

with communications agencies for communications facilities. Chapter 17 provides details on

communications considerations.

When locating a new substation, coordinate the location, design, and construction with other utilities

operating in the area. Other utility concerns include but are not limited to:

1. Telecommunications

2. Cable television

3. Water and sewer

4. Gas

5. Radio and television stations

There should be little difficulty ensuring proper substation interfacing with distribution, subtransmission,

and transmission lines. Timely plans should be made so there is mutual agreement between the substation

engineer and the various line engineers on the following:

1. Connecting hardware procurement responsibility

2. Mating of hardware to line support structure

3. Line identifications and electrical connections to suit planning engineering requirements

4. Substation orientation and line approach

5. Phase conductor and shield wire identification

6. Pull-off elevations, spacings, tensions, and angles

2.4.1 Line Tension

Confusion sometimes occurs in the matter of specifying line tensions in substations. In some cases, line

tensions on the line side of a line approach or deadend structure will be much greater than on the line

support structure in the substation. The substation engineer should specify the tension that will result in

the maximum load on the substation line support structure with the wire under the most severe

combination of temperature, wind, and ice loading. The condition at which maximum tension occurs has

to be known in order to select appropriate overload factors. Chapter 7, “Structures,” covers overload

factor selection.

As a general rule, takeoff tensions should not exceed 8900 newtons (2000 pounds) per conductor for

small distribution substations. However, the incoming transmission line alignment, wire size, and

elevation differences can increase the required tensions.

2.5 RELIABILITY CONSIDERATIONS

A prime objective in the operation of an electric power system is to provide reliable service within

acceptable voltage limits. Information on reliability may be found in ANSI Std. C84.1-1995, “Electric

Power Systems and Equipment-Voltage Rating (60 Hz).” Cooperatives that design substations to operate

within the voltage levels specified in this ANSI Standard should have reasonably reliable substations.
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2.6 OPERATING CONSIDERATIONS

For simplicity and ease of maintenance, substation equipment arrangements, electrical connections, signs,

and nameplates should be as clear and concise as possible. Information on safety signs can be found in

ANSI Std. Z535.2, “Environmental and Facility Safety Signs.”

A substation may occasionally experience emergency operating conditions requiring equipment to

perform under abnormal situations. Depending on the length of time, the provision of unusual currentcarrying capacity of some equipment or connections should always be considered and appropriately

accounted for in the design.

2.7 SAFETY CONSIDERATIONS

It is paramount that substations be safe for the general public and for operating and maintenance

personnel. Practical approaches include the employment and training of qualified personnel, appropriate

working rules and procedures, proper design, and correct construction. The safeguarding of equipment

also needs to be considered in substation design.

Personnel working standards are prescribed by regulations issued by the Occupational Safety and Health

Administration (OSHA). These regulations are included in 29 CFR 1910 for general industry and

29 CFR 1926 for construction. In addition, various states may have standards the same as or stricter than

those of OSHA. The engineer is expected to follow the regulations appropriate to the jurisdiction in

which a substation is built.

It should be recognized that this bulletin presents substation design guidance information only and not

detailed regulatory provisions, especially related to safety. The engineer is responsible for researching

and ensuring substations are designed in compliance with the applicable requirements of RUS, the

National Electrical Safety Code, National Electrical Code, OSHA, and local regulations. The engineer is

also responsible for analyzing expected local conditions, and, where warranted, including provisions in

substation designs beyond the minimum provisions for safety established in the various regulatory codes.

2.8 MAINTENANCE CONSIDERATIONS

Substation design needs to allow maintenance to be accomplished with a minimum impact on a

substation’s operation. Allocation of adequate working space is necessary.

In selecting equipment, consider the service intervals recommended by the manufacturers and past

experience in using a particular manufacturer’s equipment.

See Chapter 20, “Maintenance,” for more information.

2.9 REFERENCES

7 CFR 1792, subpart C, “Seismic Safety of Federally Assisted New Building Construction”

7 CFR 1794, “Environmental Policies and Procedures.”

40 CFR 110, “Discharge of Oil.”

40 CFR 112, “Oil Pollution Prevention.”
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ANSI Std. C84.1, “Electric Power Systems and Equipment-Voltage Rating (60 Hz).”

ANSI Std. Z535.2, “Environmental and Facility Safety Signs.”

ANSI/ASCE Std. 7-95, “Minimum Design Loads for Buildings and Other Structures.”

ANSI/IEEE Std. C2, National Electrical Safety Code.

ANSI/IEEE Std. C37.30, “Standard Definitions and Requirements for High-Voltage Air Switches,

Insulators, and Bus Supports.”

ANSI/IEEE Std. 367, “Recommended Practice for Determining the Electric Power Station Ground

Potential Rise and Induced Voltage from a Power Fault.”

ANSI/IEEE Std. 487, “Communication Facilities Serving Electric Power Stations, Guide for the

Protection of Wire Line.”

Bragdon, C.R., “Municipal Noise Ordinances: 1975,” Sound and Vibration 9(12): 24-30 (December

1975).

Federal Interagency Committee on Urban Noise, 1980, p. 5.

Fink and Carroll, Standard Handbook for Electrical Engineers. Section 11-100. 10th ed. New York:

McGraw-Hill, 1968.

IEEE Std. C57.114, “IEEE Seismic Guide for Power Transformers and Reactors.”

IEEE Std. 980, “IEEE Guide for Containment and Control of Oil Spills in Substations.”

IEEE Std. 1119, “IEEE Guide for Fence Safety Clearances.”

IEEE Std. 1127, “IEEE Guide for the Design, Construction, and Operation of Safe and Reliable

Substations for Community Acceptance and Environmental Compatibility.”

International Conference of Building Officials (ICBO), Uniform Building Code—1997.

Lawless, E.B., “Noise Control Regulations and Effects Upon Substation Design, Annual Conference of

Engineering and Operation Division,” Southeastern Electric Exchange, New Orleans, Louisiana,

April 26-27, 1976.

National Rural Electric Cooperative Association, Cooperative Research Network, Animal-Caused

Outages. Project 94-5. Arlington, Va.: NRECA, 1996.

Occupational Safety and Health Administration (OSHA) Documents; 29 Code of Federal Regulations

Part 1910, General Industry, and Part 1926, Construction.

Pedersen, R.S., “Audible Noise Reduction in New and Existing Substations,” Engineering, and Operating

Conference, Pacific Coast Electrical Association, San Francisco, California, March 18-19, 1976.

RUS Bulletin 1724E-302, “Design Guide for Oil Spill Prevention and Control at Substations.”
Bulletin 1724E-300

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RUS Bulletin 1794A-600, “Guide for Preparing an Environmental Report for Categorically Excluded

Projects."

RUS Bulletin 1794-601, “Guide for Preparing an Environmental Report for Electric Projects Requiring an

Environmental Assessment”

Schulz, M.W., “Transformer Audible Noise,” IEEE Power Engineering Society Summer Meeting,

Portland, Oregon, July 17-23, 1976.

U.S. Environmental Protection Agency, “Information on Levels of Environmental Noise Requisite to

Protect Public Health and Welfare with an Adequate Margin of Safety,” Report No. 550/19-74-004,

Washington, D.C., March, 1974.

U.S. Environmental Protection Agency, “Public Health and Welfare Criteria for Noise,” Report No.

550/9-73-002, Washington, D.C., July 27, 1973.
Bulletin 1724E-300

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CHAPTER 3

DOCUMENTS

3.1 GENERAL

The primary function of a substation design engineer is to produce or supervise the development of

formal plans from which a substation can be constructed.

Section 3.1.1 lists documents or studies that may also be required as part of the engineer’s responsibility.

The timing and chronological order of the documents may vary, depending on the particular substation’s

requirements.

3.1.1 Possible Documents or Studies Required of the Engineer

1. Site Comparison and Suitability Evaluation

2. Environmental Assessment (EA) or Environmental Report (ER)

3. Substation Design Summary Form

4. Functional One-Line Diagram

5. Application for Zoning Variance or Change

6. Specifications for Equipment

7. Request for Proposals to Furnish Equipment

8. Evaluation of Proposals to Furnish Equipment

9. Construction Plan Drawings

10. Backup Sketches and Calculations for Construction Plans

11. Substation Drawings (Detailed One-Line, Elementary, and Schematic Diagrams)

12. Requisitions for Material and Equipment

13. Application for Building Permit

14. Application for Permits for Roadway and Drainage Interface

15. Application for FCC License

16. Construction Specifications

17. Inquiry for Proposals to Furnish Construction

18. Evaluation of Contractor’s Proposals

19. Comment Letters on Equipment Vendors’ Submittals

20. Calculations for Selection of Protective Relaying and Devices

21. Economic Comparisons

Formal documentation should be clearly presented. Since the electric utility industry uses English units

for specifying substation design construction and materials, documentation may be completed using

English units of measure. Metric equivalent units may also be included in parentheses, e.g., 8.0 feet (2.45

meters). During the formulation of design, some sketching and calculations are required to arrive at

optimum designs. While these are not a part of the formal plans, they are nevertheless useful in planning

and are often valuable for future reference.

3.2 NEED FOR DOCUMENTATION

Documentation forms the basis for the expression and evaluation of engineering concepts. A document

serves as a vehicle for the cooperative and engineer to reach agreement on a particular subject. In its final

form, a document fulfills its primary role of establishing design and functional requirements. A document
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also serves as a record of what was built, specified, or evaluated. The importance of good records in

substation design deserves emphasis. Successful designs and accurate records are convenient references

for designs and for standardized approaches for new substations. Records can also be very useful in

diagnosing and correcting problems. Appendix B to this chapter is a Substation Design Summary where

design information can be recorded for future reference.

3.3 PROCEDURES

RUS has required substation design procedures and, in addition, each cooperative may have certain

procedures that suit its needs.

The chronology of a substation design is generally as shown in Table 3-1 with elapsed times varying

according to a particular project’s requirements. See 7 CFR 1726.22, “Methods of Construction,” and

7 CFR 1724.53, “Preparation of Plans and Specifications.”

Table 3-1: Substation Design Chronology

1. Identification of substation needs from Load Forecast (formerly Power Requirements Study)

and cooperative’s long-range plan

2. Pre-loan engineering

3. Application for loan; see 7 CFR 1710.119, “Loan Processing Priorities”

4. Loan approval

5. Final procurement of real estate

6. Selection of major equipment

7. Preparation of plans and specifications; see 7 CFR 1724.53, “Preparation of Plans and

Specifications”

8. RUS Form 764, “Substation and Switching Station Erection Contract,” generally required for

systems with limited construction forces

9. Design approval by RUS as stated in 7 CFR 1724.54 “Requirements for RUS approval of

plans and specifications”

10. Selection of a construction contractor

11. Construction

12. Inspection; see RUS Form 235, “Engineering Service Contract—Electric Substation Design

and Construction,” and 7 CFR 1726.403, “Project Construction Contract Closeout”

13. Testing

14. Energizing

When competitive bids are to be received for substation construction, the engineer’s role is that described

in 7 CFR 1726.19, “Use of Competitive Procurement.” See also RUS Form 764, “Substation and

Switching Station Erection Contract.”

Consultation with the RUS General Field Representative (GFR) may provide useful information and

assistance with pertinent RUS requirements.

3.4 PROCUREMENT

The methods and documentation for obtaining substation equipment are as follows:

1. Purchase order following informal quotations

2. Contract and purchase order following formal competitive bidding
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Guidelines and procedures applicable to the selection of materials and equipment include the following

documents:

• 7 CFR 1728, “Electric Standards and Specifications for Materials and Construction”

• 7 CFR 1726.22, “Methods of Construction”

• Information Publication 202-1, “List of Materials Acceptable for Use on Systems of RUS

Electrification Borrowers”

• 7 CFR 1726.21, “New Materials”

• Bulletin 43-9, “‘Buy American’ Requirement,” as updated per notice published in the Federal

Register on February 19, 1997, at 62 FR 7205

• 7 CFR 1728.20, “Establishment of Standards and Specifications”

The size and complexity of a project can greatly influence the choices in procurement. Lead times for

procurement of major and/or special equipment in many cases may favor incremental purchases of

equipment.

Smaller projects may lend themselves more to “standard package”-type procurement while the

procurement for larger projects may require many vendors.

3.5 DRAWINGS

3.5.1 General

For a basic distribution substation, a “One-Line Diagram” and “Plot Plan” may be the only drawings that

need to be custom made by the engineer. For example, if a substation is small, it may be possible to show

foundation details on the “Plot Plan.” Similarly, the grounding layout and details might also be shown on

a “Plot Plan.”

Larger substations will, of necessity, require more extensive documentation. RUS Form 235,

“Engineering Services Contract—Electric Substation Design and Construction,” details a basic list of

drawings often necessary.

3.5.2 Quality

3.5.2.1 Substation drawings of any kind should conform to industry accepted quality requirements.

3.5.2.2 Drafting Practice: It is recommended that drafting practices be in accordance with American

Drafting Standards Manual, ANSI Std. Y14. Prints of the drawings will be used in construction, not

always under the most convenient environmental conditions. Experience indicates a preference for

equipment outlines with detailed pictorial representations. Pertinent component interfaces and

connections should be illustrated in adequate detail for construction and record purposes. The dimensions

of pertinent distances need to be shown. Drawings, though made to scale, should not have to be scaled

for construction purposes. Thought should be given to choosing scales and lettering sizes appropriate for

the type of drawing. It would be desirable to use bar-type graphic scales on all drawings since many of

them may be reproduced in different sizes. Plans, elevations, and sections should be organized for

maximum clarity. Tolerances should be noted on drawings, such as those that specify foundation anchor

bolt locations and equipment mounting holes on control panels. Simplicity and clarity of drawings are

essential.
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3.5.2.3 Computer Drafting/Computer-Aided Design and Drafting (CADD)

3.5.2.3.1 General: Since the early 1980s the use of CADD has exploded. With proper planning, CADD

is a very productive tool. Virtually all modern substations are now designed on CADD systems.

3.5.2.3.2 Startup: Parameters need to be established before the creation of any drawings with CADD.

These parameters are basic to CADD and permit CADD to make use of its strength and flexibility to

produce quality products. These parameters will ultimately lead to the increased productivity that users

expect from CADD:

1. Establish or revise key drawing criteria. The engineer needs to know what is to be shown on

each drawing.

2. Establish legends for the symbols that will be used.

3. Standardize the line weights and text sizes.

4. Establish standard layer or level schemes.

5. Provide for the ability to isolate layers and reference other files.

6. Provide for the ability to make changes on one file and have the changes reflected on related

drawings, eliminating having to change the other drawings.

7. Establish a cell library or blocks, in a location for standard files, of items that will be

continually reused in the cooperative’s drawings.

8. Create seed files or prototype files that may be used as the base for drawing preparation.

3.5.2.3.3 Detailing Guidelines: The use of CADD generates new considerations and requires new

guidelines. However, good manual detailing practices such as the following still apply to computer

detailing:

1. Draw everything to scale if possible.

2. Use good clear dimensioning.

3. Carefully select line weights and text sizes. Use standard sizes where applicable.

4. Do not overdetail drawings with the use of CADD. It makes no sense to show the threads on

the bolts just because you can.

5. Use the cooperative’s standard detailing manuals and procedures, or coordinate with other key

design and detailing personnel in the cooperative.

6. If you wouldn’t show a detail with ink on mylar, it should not be drawn with CADD software.

7. Avoid translations. CADD software will seldom translate drawings prepared by another

vendor’s software completely accurately. It’s always best to use the cooperative’s standard

CADD software.

8. Avoid mixing drawings from different CADD packages on a project or within a cooperative.

The use of several different CADD packages within an organization will tend to lead to

confusion in detailing.

3.5.2.4 Legends, Notes, and Symbols: Put a definitive legend on the first sheet of each type of

drawing. This legend should not only include the standard symbols, but all special symbols or

designations. A set of notes is often found to be a desirable supplement on a drawing. Use judgment to

avoid overdoing notation. It may be better to consider additional details on the drawings rather than a

long list of notes. Electrical symbols should be in accordance with IEEE Std. 315, “Graphic Symbols for

Electrical and Electronics Diagrams.”

3.5.2.5 Reference Drawings: Give proper care to the listing of reference drawings to ensure a

coherent, concise pattern.
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3.5.2.6 Titles: Make drawing titles concise, accurate, and specific. They should not be so general that

the drawing itself has to be viewed to see what it covers.

3.5.2.7 Approvals: Ensure that every drawing or revision to a drawing indicates the proper approvals

and dates.

3.5.3 Types of Drawings

Following are the main types of substation construction and reference drawings often required.

Appendix A to this chapter includes checklists covering the content of some types of drawings. It is

recommended that the engineer use checklists as a design quality control tool.

1. One-Line Diagram - Switching

2. One-Line Diagram - Functional Relaying

3. Three-Line Diagram

4. Electrical Plot Plan

5. Site Preparation

6. Fence Layout

7. Electrical Layouts

8. Structure Erection Diagrams

9. Foundation Layouts

10. Grounding Layout

11. Conduit Layout

12. Control House - Architectural, Equipment, Layout, Lighting, Etc.

13. Station Service Diagrams AC and DC

14. Cable Lists and Conduit Lists

15. Bills of Material

16. Drawing List

17. Control Panels

18. Schematic and Detailed Wiring Diagrams

3.5.3.1 One-Line Diagrams: One-line diagrams serve as the major substation reference drawings and

require special emphasis. These references should be the first drawings prepared. The switching and

functional relaying information may appear on the same one-line diagram if the presentation is not too

complicated. It is recommended that one-line diagrams be prepared utilizing the “Typical Substation

Drawing Checklist” that is included in Appendix A.

Acceptable symbols for some of the most common substation equipment are illustrated in Figures 3-1

through 3-19. Generally, these symbols are based on IEEE Std. 315. Drafting templates are

commercially available to assist in developing one-line diagrams. Each symbol should be accompanied

by the pertinent equipment information indicated.
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Figure 3-1: Power Transformer (Shown with Load Tap Changer on Low-Voltage Side). Ref. IEEE

Std. 315 based on Figs. 6.4.9, 1.9.3, 1.9.7.1, and 3.9.1. Copyright © 1975. IEEE. All rights reserved.

Figure 3-2: Three-Phase Transformer with Tertiary. Ref. IEEE Std. 315. Based on

Figs. 6.4.17, 1.9.3, 1.9.7.1, and 3.9.1. Copyright © 1975. IEEE. All rights reserved.

Figure 3-3: Three-Phase Auto-Transformer. Ref. IEEE Std. 315. Based on

Figs. 6.4.8, 1.9.3, 1.9.7.1, and 3.9.1. Copyright © 1975. IEEE. All rights reserved.
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Figure 3-4: Step Voltage Regulator with Bypass Switch.

Ref. IEEE Std. 315. Based on Figs. 6.4.10.1, 4.6.1, and 14.4.1.

Copyright © 1975. IEEE. All rights reserved.

Figure 3-5: Hook Stick-Operated Disconnecting Switch.

Ref. IEEE Std. 315. Figure 4.6.1.

Copyright © 1975. IEEE. All rights reserved.

Figure 3-6: Three-Phase Gang-Operated Disconnecting Switch with Horn Gaps

and Grounding Switch. Ref. IEEE Std. 315. Figs. 4.6.1, 4.6.6, and 3.9.1.

Copyright © 1975. IEEE. All rights reserved.
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Figure 3-7: Three-Phase Double Side-Break Disconnecting Switch with Motor Operator.

Ref. IEEE Std. 315. Based on Figs. 13.1.3 and 4.6.1. Copyright © 1975. IEEE. All rights reserved.

Figure 3-8: Fused Disconnect. Ref. IEEE Std. 315. Figs 9.1.1 and 9.1.3.

Copyright © 1975. IEEE. All rights reserved.
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Figure 3-9: Oil Circuit Recloser. Ref. IEEE Std. 315. Based on Fig. 9.4.6.

Copyright © 1975. IEEE. All rights reserved.

Figure 3-10: Circuit Breaker (Shown with Bushing-Type CTs and Reclosing Relay).

(Show Polarity Marks on One-Line Functional Relaying Diagram.)

Ref. IEEE Std. 315. Based on Figs. 9.4.4, 6.4.19, and 4.5.3.

Copyright © 1975. IEEE. All Rights Reserved.

Figure 3-11: Surge Arrester. Ref. IEEE Std. 315. Based on Figs. 9.3.1 and 3.9.1.

Copyright © 1975. IEEE. All rights reserved.
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Figure 3-12: Voltage Transformer. Ref. IEEE Std. 315. Based on Figs. 3.9.1, 6.4.20, and 1.9.7.1.

Copyright © 1975. IEEE. All rights reserved.

Figure 3-13: Current Transformer. (Show Polarity Marks on Functional

Relaying One-Line Diagram.) Ref. IEEE Std. 315. Figs 6.4.18 and 1.6.3.1.

Copyright © 1975. IEEE. All rights reserved.

Figure 3-14: Coupling Capacitor with Voltage Transformer. Ref. IEEE Std. 315.

Based on Figs. 2.2.1, 2.2.15, and 6.2.7.1. Copyright © 1975. IEEE. All rights reserved.

Figure 3-15: Coupling Capacitor, Wave Trap, Tuning Unit, and Power Line Carrier

Transmitter/ Receiver. Ref. IEEE Std. 315. Based on Figs. 6.2.8.1 and 2.2.12.

Copyright © 1975. IEEE. All rights reserved.
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Figure 3-16: Disconnecting Clamp. Ref. IEEE Std. 315.

Based on Fig. 3.3.1. Copyright © 1975. IEEE. All rights reserved.

Figure 3-17: Shunt Capacitor. Ref. IEEE Std. 315. Fig. 2.2.11.

Copyright © 1975. IEEE. All rights reserved.
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Figure 3-18: One-Line Diagram Symbols. Ref. IEEE Std. 315.

Based on Figs. 5.3.4, 9.4.1, 2.1.1, 6.2.1, 3.9, and 1.3.1.

Copyright © 1975. IEEE. All rights reserved.

Figures 3-20, 3-21, and 3-22 provide elementary examples of symbols in combination. Figure 3-20 shows

a conceptual one-line diagram of a transmission substation. Figure 3-20 is provided merely to illustrate

use of some of the symbols. Figures 3-21 and 3-22 combined provide a more complete example of

equipment usage for Line 161-20. It may be observed that equipment shown on Figures 3-21 and 3-22

hardly exhausts the possibilities of equipment application for a 161 kV line. Figures 3-21 and 3-22,

moreover, indicate the desirability of having both switching and relaying one-line diagrams except for the

simpler substations.
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Figure 3-19: Typical Relay and Meter Representation. Ref. IEEE Std. C37.2-1996.

Copyright © 1975. IEEE. All rights reserved.
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Figure 3-20: Conceptual One-Line Diagram
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Figure 3-21: Partial Switching One-Line Diagram (See Figure 3-20)
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Figure 3-22: Partial Functional Relaying One-Line Diagram (See Figure 3-20)
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3.5.3.2 Cable Lists and Conduit Lists: Cables may be identified on a drawing, such as a conduit

layout, if the number of cables is not large. On large stations, it generally is desirable to have a separate

cable identification list. A cable identification system should be devised to indicate the location of one

end of each cable and the function of the cable. An alphanumeric designation often works well. In such a

system, C4-3 could be a cable from a circuit breaker at location C4 on a grid system where C designates

an equipment row centerline in a series A, B, C, D, etc., and 4 designates a row centerline in a series

1,2,3,4,5,6, etc., at a right angle to centerline C. The -3 could represent a cable for control.

Different arabic numerals could be used for other functions.

3.5.3.3 Bills of Material: As a general rule, all elements of work in a substation should have a list of

material. When such lists comprise a multisheet drawing, they are known as Bills of Material. Formats

should be devised to include the following information as a minimum:

1. Identification of the substation

2. Alphanumeric code name for items that may appear on a construction drawing for

identification and location

3. Adequate description of each item

4. Reference to the applicable purchasing document

5. Quantity of the item

6. Reference to drawing(s) on which the item is shown for installation

3.5.3.4 Drawing List: It is recommended that every substation have a drawing list that includes, at the

cooperative’s and engineer’s discretion, manufacturers’ drawings, design calculations, the cooperative’s

standard drawings, etc.

3.5.3.5 Schematic and Detailed Wiring Diagrams: These wiring diagrams should be prepared

following the guidelines in ANSI Std. Y14.15, “Electrical and Electronic Diagrams.”

3.6 STUDIES

For many substations, it will be necessary to make a number of studies such as feasibility studies,

economic comparisons, voltage drop calculations for control and auxiliary power circuits, rigid and strain

bus design comparisons, structural design calculations, etc. The results of these studies along with the

calculations should be retained with other documents relating to the particular substation.

3.7 REFERENCES

7 CFR 1710.119, “Loan Processing Priorities.”

7 CFR 1724.53, “Preparation of Plans and Specifications.”

7 CFR 1726.19, “Use of Competitive Procurement.”

7 CFR 1726.21, “New Materials.”

7 CFR 1726.22, “Methods of Construction.”

7 CFR 1726.35, “Submission of Documents to RUS.”
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7 CFR 1726.403, “Project Construction Contract Closeout.”

7 CFR 1728, “Electric Standards and Specification for Materials and Construction.”

7 CFR 1728.20, “Establishment of Standards and Specifications.”

ANSI Std. C37.2, “Standard for Electrical Power System Device Function Numbers and Contact

Designations.”

ANSI Std. Y14, American Drafting Standards Manual.

ANSI Std. Y14.15, “Electrical and Electronic Diagrams.”

IEEE Std. 315, “Graphic Symbols for Electrical and Electronic Diagrams.”

RUS Bulletin 43-9, “Buy American Requirement.”

RUS Form 235, “Engineering Service Contract—Electric Substation Design and Construction.”

RUS Form 764, “Substation and Switching Station Erection Contract.”

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”
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APPENDIX A

TYPICAL SUBSTATION DRAWING CHECKLIST

GENERAL – FOR ALL DRAWINGS

A. COVER SHEET/INDEX

B. LEGEND

C. ELEMENTARY ONE-LINE DIAGRAM(S)

D. RELAY ONE-LINE DIAGRAM(S)

E. GENERAL ARRANGEMENT PLAN

F. SITE PLANS, SECTIONS, AND DETAILS

G. SUBSTATION PLAN, SECTIONS, AND DETAILS

H. FOUNDATION PLAN AND DETAILS

I. STRUCTURE PLAN AND DETAILS

J. GROUNDING PLAN AND DETAILS

K. RACEWAY PLAN AND DETAILS

L. DUCT BANK AND HIGH-VOLTAGE CABLE PLAN AND DETAILS

M. CONTROL BUILDING PLANS, SECTIONS, AND DETAILS

N. SUBSTATION BILL OF MATERIALS

O. RELAY CONTROL PANEL (SWITCHBOARD) LAYOUTS AND WIRING DIAGRAMS

P. THREE-LINE DIAGRAMS, AC AND DC SCHEMATICS

Q. MISCELLANEOUS EQUIPMENT YARD EXTERNAL CONNECTION DIAGRAMS
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GENERAL - FOR ALL DRAWINGS

____________ 1. Title block.

____________ 2. Engineer’s seal (verify whether engineer needs to sign the seal).

____________ 3. Drawing dates (input date the drawing is issued for owner approval).

____________ 4. Revision block.

____________ 5. Signature lines:

____________ a. Detailed - Detailers name (i.e., J.A. JONES) who initially made the drawing.

____________ b. Designed - Design engineer’s name (i.e. T.R. SMITH).

____________ c. Checked - Initials (i.e., L.M.F.) of the engineer who checked the drawing; the

same engineer may not check all contract drawings.

____________ 6. Symbology is correct per Legend drawing.

____________ 7. Drawing coordinate system is provided on border margins.

____________ 8. Drawing is of material satisfactory to the cooperative.

____________ 9. Drawing is of a size satisfactory to the cooperative.

____________ 10. Drawing is identified as satisfactory to the cooperative.

____________ 11. All line work and lettering are reproducible.

____________ 12. The smallest lettering is readable at the smallest proposed reduction size.

____________ 13. Consideration has been given to overall organization of drawing to minimize

field inconvenience.

____________ 14. Drawing avoids ambiguities, incompleteness, lack of clarity, misleading

emphasis, etc.

____________ 15. Legends, notes, symbols have been carefully reviewed for correctness and

completeness.

____________ 16. Appropriate drawings are referenced.

____________ 17. All changes are incorporated as required by the cooperative or RUS.

____________ Additional for Plan, Sections, Elevations, Details, and Panel Layouts.

____________ 18. Bar scale (engineer’s scale only).

____________ 19. Detail, Section, or Elevation Designation and Title.

____________ Additional for Plan, Drawings, Detail Plan Views, One-Line and Three-Line

diagrams.

____________ 20. North arrow (reference to grid, true, or magnetic north).

A. COVER SHEET/INDEX (MAY BE MORE THAN ONE DRAWING)

____________ 1. Engineer’s seal

____________ 2. Cooperative name

____________ 3. Cooperative logo

____________ 4. Project description

____________ 5. Contract number and name

____________ 6. List of contract drawings

____________ 7. Vicinity map (with north arrow)

____________ 8. List of reference drawings

____________ 9. Project number

____________ 10. Year
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B. LEGEND

Include the “General - for All Drawings” items.

1. List of all symbols used for the drawings (do not have individual legends on

other drawings with the exception of complex Civil Site Grading Plans).

C. ELEMENTARY ONE-LINE DIAGRAM(S)

Include the “General - for All Drawings” items

____________ 1. Substation names and voltages

____________ 2. Breakers with PCB numbers

____________ 3. Disconnect switches with numbers

____________ 4. Line/major equipment designations

____________ 5. Phasing

____________ 6. Future equipment

7. Transmission lines:

____________ a. Length

____________ b. Conductors/stranding

____________ c. Transpositions

____________ 8. Bus and relative location, physically oriented as possible

____________ 9. Interties to interconnecting utilities - phasing difference between utilities

____________ 10. Power fuses

____________ 11. Other information needed from a switching standpoint to define overall system

D. RELAY ONE-LINE DIAGRAM(S)

Include the “General - for All Drawings” items.

1. Power One-line:

____________ a. Incoming lines/designations and voltages

____________ b. Disconnect switches and numbers

____________ c. Surge arresters/quantity and rating

d. Power transformers (in equipment box):

 ___________ (1) Winding type - auto or multiple winding and tertiary

____________ (2) Surge arresters

____________ (3) Phasing

____________ (4) Bushings/designations

____________ (5) Neutral/ground connection

(6) Transformer designations:

____________ (a) Voltage rating

____________ (b) MVA rating

____________ (c) Cooling rating

____________ (d) HV taps

____________ (e) LV taps

____________ (f) LTC (if applicable)

____________ (g) Impedance for all winding connections

____________ (h) Winding connection diagram indicating phasing and voltage

relationships at bushings

____________ 2. Power fuses w/ continuous current rating

3. Station service transformer:
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____________ a. Quantity

____________ b. kVA rating

____________ c. Transformer type

____________ d. Voltage ratings

____________ e. Taps

____________ f. Secondary breaker or fuse if located in yard near transformer

____________ g. Reference to low-voltage AC drawing

____________ 4. High-voltage bus with designations on main bus and phasing, connection dots

5. Power circuit breakers:

____________ a. Bushing pole numbers

____________ b. Cabinet location

____________ c. Designation

____________ d. Continuous current rating

____________ e. Breaker number

6. CCVTs, CVTs, or PTs:

____________ a. Primary winding

____________ b. Secondary winding with terminal designations

____________ c. Quantity (if more than one)

____________ d. Phase designation

____________ e. Voltage rating for all windings

____________ f. Ratio for all windings

____________ g. Capacitance of device

7. Line traps

____________ a. Designation

____________ b. Phase location

____________ c. Continuous current rating

8. Miscellaneous equipment:

____________ a. Correct symbol per legend

____________ b. Designation

____________ c. Phasing

____________ d. Quantity (if more than one)

____________ e. Major equipment ratings

9. Miscellaneous:

____________ a. Future bus connections

____________ b. Temporary bus connections:

1. Clear differentiation between permanent -vs- temporary

____________ 2. Different phases of construction (permanent -vs- temporary)

____________ c. References to other drawings

____________ d. Bill of material #’s for major equipment

____________ e. Drawing coordinate system

10. Protection/controls:

a. Current transformers/circuits:

____________ (1) Correct orientation of symbol

____________ (2) Multi ratio -vs- single ratio

____________ (3) Polarity marks

____________ (4) Symbol for wye or delta connection

____________ (5) Quantity (if more than one)

____________ (6) Maximum ratio for multi-ratio

____________ (7) Ratio combinations for dual rated CTs

____________ (8) Connected ratio
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____________ (9) Shorted if not used

____________ (10) Circuits short as possible to minimize confusion

____________ (11) Fewest line crossings as possible to minimize confusion

____________ (12) Straight through devices - in and out

____________ (13) Test plug arrows pointed properly

____________ (14) Polarizing currents in and out on 45 degree angle

b. Potential circuits:

____________ (1) Potential device secondary winding

____________ (2) Potential device secondary connections

____________ (3) Fuses and contact current ratings

____________ (4) Test points as appropriate

____________ (5) Into instruments on a square angle

____________ (6) Short as possible to minimize confusion

____________ (7) Fewest line crossings as possible to minimize confusion

c. Equipment enclosure boxes:

____________ (1) Transformers

____________ (2) Fuse and terminal boxes

____________ (3) Designations and phasing as applicable

d. Instruments:

____________ (1) Circle or box per legend

____________ (2) Designations or suffixes per legend

____________ (3) Location symbol

____________ (4) Quantity (if more than one)

e. Control logic:

____________ (1) Short as possible to minimize confusion

____________ (2) Fewest line crossings as possible to minimize confusion

____________ (3) Arrowhead toward the direction of action

____________ (4) Arrowhead only where action splits or comes together for a common

function

____________ (5) Contact designations where applicable to show correct logic

____________ (6) Diodes where applicable and used to control the logic

____________ (7) If not obvious, primary action of control identified (Trip, etc.)

E. GENERAL ARRANGEMENT PLAN

Include the “General - for All Drawings” items.

1. First transmission structure outside the fence, minimum, with location

coordinates

____________ 2. Minimum of two survey monuments with elevations and dimensions to the

substation base lines

____________ 3. Coordinates (or dimensions to base line) of centerline of transmission line

termination structure

____________ 4. Transmission line voltage and name

____________ 5. Transmission line right-of-way with tie into substation monuments

____________ 6. Property lines and other utility corridors or rights-of-way

____________ 7. Baseline

____________ 8. Borrow and waste area

____________ 9. Trash area

____________ 10. Storage areas
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____________ 11. Site access

____________ 12. Vicinity map with ties to state plane coordinates

F. SITE PLANS, SECTIONS, AND DETAILS

Include the “General - for All Drawings” items.

1. Site Plan/Grading Plan:

____________ a. Baseline

____________ b. Benchmark

____________ c. Fence coordinates

____________ d. State plane grid system

____________ e. New and existing grade

____________ f. Buried facilities

____________ g. Borrow area

____________ h. Access roads

2. Site Sections/Grading Sections and Details:

a. Sections:

____________ (1) Fence location

____________ (2) Baseline location

____________ (3) Elevations

____________ (4) New and existing grade

____________ b. Fence details

____________ c. Gate details

G. SUBSTATION PLAN, SECTIONS, AND DETAILS

Include the “General - for All Drawings” items.

1. Substation Plan:

____________ a. Fence

____________ b. Warning signs

c. Equipment and structures:

____________ (1) Deadend structure

____________ (2) Breakers

____________ (3) Switches

____________ (4) Control building

____________ (5) Instrument transformers

____________ (6) Power transformer

____________ (7) Switchgear

____________ (8) Reactors

____________ (9) Bus supports

____________ (10) Static masts

____________ (11) Capacitors

____________ (12) Surge arresters

____________ (13) Cable trench and designated drive paths

d. Bus and conductor:

____________ (1) End bells

____________ (2) Grounding studs

____________ (3) Bus A-frame connection

____________ (4) Jumper connections
Bulletin 1724E-300

Appendix A, Chapter 3

Page 79

____________ (5) Strain bus

____________ (6) Bus cutting schedule

____________ e. Phasing (transmission line phases and bus phases)

____________ f. Transmission line voltage and name designation

____________ g. Section reference callouts

____________ h. Detail reference callouts

____________ i. Dimensions (fence to major equipment if dimensions do not show up on

 section drawings)

____________ j. Future equipment

____________ k. Notes

____________ l. Baseline

2. Substation Sections and Details:

______ a. Bill of Material callouts (if typical is used, it is only for the section in

question)

____________ b. Dimensions (centerline of equipment)

____________ c. Bottom of baseplate callout (each section)

____________ d. Conductor and static wire takeoff heights, stranding, and maximum

allowable tensions

e. Bus support type callout (may be shown on plan):

____________ (1) Slip

____________ (2) Fixed

____________ (3) Expansion

____________ f. Detail reference callouts

g. Bus and conductor:

____________ (1) End bells

____________ (2) Bus A-frame connections

____________ (3) Grounding studs

____________ (4) Jumper connections

____________ h. Disconnect switches and switch operators

____________ i. Area lighting

j. Notes:

____________ (1) Reference assemblies

____________ (2) Reference grounding details

____________ k. Transmission line voltage, name designation, conductor, and stranding

____________ l. Phasing

____________ m. Equipment elevation differences to bottom of baseplate; elevation

differences are noted if leveling nuts are used on some equipment

____________ n. Elevation breaks in bus

____________ o. Junction boxes/fuse boxes

____________ p. Welding outlet locations

____________ q. Telephone location

3. Substation Details:

____________ a. Bill of material callouts

____________ b. Reference notes to other details

H. FOUNDATION PLAN AND DETAILS

Include the “General - for All Drawings” items.

1. Foundation Plan:
Bulletin 1724E-300

Appendix A, Chapter 3

Page 80

____________ a. Foundation key

____________ b. T.O.C. elevations

____________ c. Baselines

____________ d. Monuments with coordinates and elevations

____________ e. Buried facilities

____________ f. Fence

g. Foundations:

____________ (1) Equipment

____________ (2) Deadend structures

____________ (3) Static masts (if any)

____________ (4) Control building

____________ (5) Cable trench

____________ (6) Oil containment system

h. Dimensions - to centerline of all foundations, unless noted otherwise (should

match with centerlines on foundation details, other dimensions as needed for

clarification):

____________ (1) Cable trench

____________ (2) Centerline of drilled shafts

____________ (3) Corner of large foundations

____________ i. Manholes and handholes

2. Foundation Details:

____________ a. Drilled shaft schedule

____________ b. Anchor bolt detail

____________ c. North arrow on Plan Views (reference to grid, true, or magnetic north).

____________ d. Anchor bolt locations

____________ e. Miscellaneous foundations

____________ f. Control building foundations

I. STRUCTURE PLAN AND DETAILS

Include the “General - for All Drawings” items.

1. Structure Plan:

NOTE: On most substations it is sufficient to incorporate Structure Plan design

with the Substation Plan drawing. Therefore a separate Structure Plan drawing is

not required. For more complex substations, a Structure Plan may be required.

____________ a. Loading table

____________ b. Baselines

____________ c. Monuments with coordinates and elevations

____________ d. Fence

____________ e. Dimensions - to centerlines of all structures, unless noted otherwise (should

match with centerlines on structure details, other dimensions as needed for

clarification).

f. Notes:

____________ (1) Definition of terms

____________ (2) Definition of symbols

2. Structure Details:

____________ a. Loading table.

b. Notes:

____________ (1) Definition of terms
Bulletin 1724E-300

Appendix A, Chapter 3

Page 81

____________ (2) Definition of symbols

J. GROUNDING PLAN & DETAILS

Include the “General - for All Drawings” items.

1. Grounding Plan:

____________ a. Baseline

____________ b. Dimension ground grid - if necessary

____________ c. Reference grounding details

____________ d. Cable trench ground

____________ e. Fence ground

____________ f. Switch operator mat

____________ g. Riser locations

____________ h. Bill of material for different size conductor

____________ i. Designation symbols per legend

2. Grounding Details:

____________ a. Reference notes to other details

____________ b. Typical equipment grounding

____________ c. Typical structure grounding

____________ d. Typical power transformer grounding

____________ e. Typical switch grounding

____________ f. Typical fence and gate grounding

____________ g. Any specific required grounding

K. RACEWAY PLAN AND DETAILS

Include the “General - for All Drawings” items.

1. Raceway Plan:

____________ a. Baseline

____________ b. Raceway schedule (may be a separate database list)

____________ c. Conduit and direct-buried cable with approximate routing

____________ d. Conduit and direct-buried cable designations

____________ e. Cable trench

____________ f. Yard lighting symbols

____________ g. Yard receptacles

____________ h. Detail references

____________ i. Major equipment identifications

____________ j. Manholes and handholes

2. Raceway Details:

____________ a. Reference notes to other details

____________ b. Conduit installation to equipment

____________ c. Control and lighting cable installation to equipment

____________ d. Major equipment identifications

____________ e. Cable trench details

L. DUCT BANK AND HIGH-VOLTAGE CABLE PLAN AND DETAILS

Include the “General - for All Drawings” items.

1. Duct Bank and High-Voltage Cable Plan and Profiles:
Bulletin 1724E-300

Appendix A, Chapter 3

Page 82

a. Duct bank curve data table:

____________ (1) Delta

____________ (2) Radius

____________ (3) Length

____________ (4) Tangent

____________ b. Stationing

____________ c. Northing and easting for beginning and end of duct bank

____________ d. Duct bank bearing and identification

____________ e. Finished grade and existing grade

2. Duct Bank and High-Voltage Cable Horizontal and Vertical Profiles, Sections,

and Details:

____________ a. Reference notes to other details

____________ b. Duct size, quantity, and arrangement

____________ c. Reinforcing steel

____________ d. Depth, finished grade, backfill, and clearances

M. CONTROL BUILDING PLANS, SECTIONS, AND DETAILS

Include the “General - for All Drawings” items.

1. Control Building Electrical Plan and Sections:

a. Equipment Plan:

____________ (1) Panel boards

____________ (2) Batteries

____________ (3) Battery charger

____________ (4) AC/DC power panels

____________ (5) Eye wash

____________ (6) Table & chair

____________ (7) Fuse boxes

____________ (8) Fire extinguisher

____________ (9) Exit sign

____________ (10) Dimensions

b. Equipment List:

____________ (1) Bill of material item number

____________ (2) Key number

____________ (3) Equipment description

c. Raceway Plan:

____________ (1) Equipment

____________ (2) Conduit

____________ (3) Raceway callouts

(4) Cable tray (if required):

(a) Tray key:

____________ [1] Key

____________ [2] Description

____________ [3] Size

____________ (5) Building cable trench (if required)

____________ (6) Raceway number

____________ (7) Raceway size

____________ (8) Circuit numbers (per Circuit Schedule) of each raceway

d. Lighting and grounding plan:
Bulletin 1724E-300

Appendix A, Chapter 3

Page 83

____________ (1) Lights (with correct legend symbol)

____________ (2) Exit sign location

____________ (3) Switches (location and type)

____________ (4) Receptacles

____________ (5) Circuit designations

____________ (6) Ground conductor locations

____________ (7) Ground connections

____________ (8) Equipment

____________ (9) Cable tray (if required)

2. Control Building Mechanical (HVAC) Plan and Sections:

____________ a. Design and detailing may be done by mechanical discipline.

3. Control Building Architectural Plan and Sections:

____________ a. Design and detailing may be done by architectural discipline.

N. SUBSTATION BILL OF MATERIALS

(May be in database format.)

O. RELAY CONTROL PANEL (SWITCHBOARD) LAYOUTS AND WIRING

DIAGRAMS

Include the “General - for All Drawings” items.

1. Layouts:

a. Front view:

____________ (1) Panel designation

____________ (2) Mimic bus

____________ (3) Relays

____________ (4) Future relays

____________ (5) Control switches

____________ (6) Test switches

____________ (7) Panel dimensions

____________ (8) Future panels

b. Rear view:

____________ (1) Relays

____________ (2) Future relays

____________ (3) Panel designation

____________ c. Nameplate schedule

____________ d. Relay Bill of Material

2. Wiring Diagrams:

____________ a. Schematic reference

____________ b. Notes:

____________ (1) Definition of terms

____________ (2) Definition of symbols not shown on Legend sheet

____________ c. Device Internal Diagrams (may be a separate drawing)

____________ d. Bill of Material (may be a separate database)

______ e. Device graphic showing terminals; device located on Wiring Diagram in

general proximity of device location as installed on Layout

____________ f. Device Designation and Wiring Termination list adjacent to each device

graphic
Bulletin 1724E-300

Appendix A, Chapter 3

Page 84

Example: UA

1 - CA1

2 - BD7

L1 - UA2

L2 - UA4

____________ g. Terminal blocks with external cable and panel-to-panel circuit connections

P. THREE-LINE DIAGRAMS, AC AND DC SCHEMATICS

Include the “General - for All Drawings” items.

1. Three-Line Diagrams

a. Power Three-Line:

____________ (1) Three phases

____________ (2) Physically oriented

____________ (3) Phasing

b. PCBs:

____________ (1) Bushing pole location and number

____________ (2) Control cabinet

____________ (3) Breaker number

c. Disconnect switches:

____________ (1) Group-operated/single phase

____________ (2) Switch number

d. Surge arresters:

____________ (1) Quantity

____________ (2) Voltage rating

____________ e. Line designations

____________ f. Line voltage

g. CCVTs, CVTs, and PTs:

____________ (1) Capacitors

____________ (2) Drain coil

____________ (3) Primary winding

____________ (4) Secondary winding

____________ (5) Heaters

____________ (6) Secondary terminal block designations

____________ (7) Carrier taps, if applicable

____________ (8) LTU

____________ (9) Phase identification

h. Current transformers:

____________ (1) Correct orientation as one-line diagrams

____________ (2) Multi ratio vs. single ratio

____________ (3) Polarity marks

____________ (4) Ratio combinations for dual rated CTs

____________ (5) Maximum ratio for multiratio CTs

____________ (6) Connected ratio for multiratio CTs

____________ (7) External terminals connected to external circuits
Bulletin 1724E-300

Appendix A, Chapter 3

Page 85

____________ (8) Jumpers

____________ (9) Grounds if applicable

i. Circuit designations:

____________ (1) Each circuit identified per circuit schedule designation

____________ (2) Terminal conductors shown with color coding

____________ (3) Spare conductors indicated

____________ (4) Shield tape or ground indicated

____________ (5) Circuit grounds indicated, if applicable

j. Power fuses:

____________ (1) Continuous current rating

k. Transformers:

____________ (1) Surge arresters

____________ (2) Bushing identification

____________ (3) Phasing

____________ (4) LTC

____________ (5) NLTC

____________ (6) Winding connections

____________ (7) Neutral

____________ (8) Transformer identification

____________ (9) Voltage ratings

____________ (10) MVA ratings

____________ (11) Cooling ratings

____________ (12) Temperature ratings

l. Major equipment:

____________ (1) Power ratings

____________ (2) Voltage ratings

____________ (3) Current ratings

____________ (4) Identification

m. Miscellaneous:

____________ (1) Equipment/cabinet enclosures

____________ (2) Notes as applicable for clarification

2. AC Schematics

a. Current circuits for power circuit breakers, transformers and generators, and

circuit switches and motor-operated disconnect switches:

(1) Relay and meter current coils, and polarizing, neutral protection, and

differential protection circuits:

(a) Circuit designations:

____________ (1) Each circuit identified per circuit schedule designation

____________ (2) Terminal conductors shown with color coding

____________ (3) Spare conductors indicated

____________ (4) Shield tape or ground indicated

____________ (5) Circuit grounds indicated, if applicable

____________ (b) Location in circuit and proper orientation

____________ (c) Polarity (if applicable)

(d) Phase:

____________ (1) Proper orientation

____________ (2) Terminal and connection points

____________ (e) Device connections and terminals

____________ (f) Current switches normal position: grounded, shared, open, or closed
Bulletin 1724E-300

Appendix A, Chapter 3

Page 86

____________ (g) Circuit ground located at devic e or at panel

(h) Miscellaneous current devices:

____________ (1) Fault recorders

____________ (2) Sequence of events recorders

(i) LTC current circuits:

____________ (1) Vacuum interrupters

b. Potential circuits for power circuit breakers, transformers and generators, and

circuit switches and motor-operated disconnect switches:

(1) Relay and meter voltage coils and polarizing, synchronizing, and

underfrequency load-shedding circuits:

(a) Circuit designations:

____________ (1) Each circuit identified per circuit schedule designation

____________ (2) Terminal conductors shown with color coding

____________ (3) Spare conductors indicated

____________ (4) Shield tape or ground indicated

____________ (5) Circuit grounds indicated, if applicable

____________ (b) Location in circuit and proper orientation

____________ (c) Polarity (if applicable)

____________ (d) Phase

____________ (e) Device connection and terminal points

____________ (f) Voltage switches normal position: grounded, shorted, open, or closed

____________ (g) Circuit ground located at device or at panel

(h) Miscellaneous voltage devices:

____________ (1) Fault recorders

____________ (2) Sequence of events recorders

____________ (3) Carrier blocking circuits

(4) Auxiliaries:

____________ (a) Motors

____________ (b) Heaters

____________ (c) Lights

____________ (d) Miscellaneous

____________ (i) LTC circuits and controls

3. DC Schematics:

a. Circuit designations:

____________ (1) Each circuit identified per circuit schedule designation

____________ (2) Terminal conductors shown with color coding

____________ (3) Spare conductors indicated

____________ (4) Shield tape or ground indicated

____________ (5) Circuit grounds indicated, if applicable

b. Relay trip and protection circuits:

(1) Power circuit breakers:

(a) Trip circuits:

(1) Protective relay circuits:

____________ (a) Internal coils and contacts

____________ (b) Target coils and contacts

____________ (c) MOVs and transistors

____________ (d) Diodes and rectifiers

____________ (e) Resistors and capacitors

____________ (f) Relay taps and jumpers

(2) Auxiliary relays:
Bulletin 1724E-300

Appendix A, Chapter 3

Page 87

____________ (a) Coils

____________ (b) Contacts

____________ (c) Miscellaneous devices

____________ (d) Spare device contacts

(3) Trip-blocking contacts:

____________ (a) Control switch contacts

____________ (b) Blocking relay coils and contacts

____________ (4) SCADA control contacts

(5) Contact callout tables:

____________ (a) Relay contacts

____________ (b) Switch contacts

(6) Switch nameplates (escutcheons):

____________ (a) Positions

(b) Close circuits:

(1) Carrier start/stop circuits:

____________ (a) Relay terminals and connections.

(b) Wire and device labels:

____________ [1] Transmit

____________ [2] Receive

(2) Close block circuits:

____________ (a) Relay coils and contacts

____________ (b) Switch contacts

(3) Reclosing relay:

____________ (a) Coils

(b) Contacts:

____________ [1] Relays

____________ [2] Switches

____________ (4) SCADA control contacts

(c) Auxiliary circuits:

____________ (1) Motors

____________ (2) Alarm points

____________ (3) Miscellaneous

(d) Breaker Failure Relaying:

(1) Relays:

____________ (a) Internal coils and contacts

____________ (b) Target coils and contacts

____________ (c) MOVs and transistors

____________ (d) Diodes and rectifiers

____________ (e) Resistors and capacitors

____________ (f) Relay taps and jumpers

____________ (2) Initiate contacts

____________ (3) Contact callout tables

(2) Transformers and generators:

(a) Trip schemes:

(1) Differential circuits for power transformer, generator and bus:

(a) Protective relay circuits:

____________ [1] Internal coils and contacts

____________ [2] Target coils and contacts

____________ [3] MOVs and transistors
Bulletin 1724E-300

Appendix A, Chapter 3

Page 88

____________ [4] Diodes and rectifiers

____________ [5] Resistors and capacitors

____________ [6] Relay taps and jumpers

____________ [7] Transformers and power supplies

(b) Trip contacts:

____________ [1] Contact callout tables

(c) Auxiliary relays:

____________ [1] References to breakers tripped and/or devices operated

____________ [2] Internal relay circuits as necessary

____________ (d) Relay terminals and connections

(2) Sudden pressure (transformer):

(a) Protective relay circuits:

____________ [1] Internal coils and contacts

____________ [2] Target coils and contacts

____________ [3] MOVs and transistors

____________ [4] Diodes and rectifiers

____________ [5] Resistors and capacitors

____________ [6] Relay taps and jumpers

____________ [7] Transformers and power supplies

____________ (b) Sudden pressure switch

(3) Neutral, highside, and remote trip schemes:

(a) Protective relay circuits:

____________ [1] Internal coils and contacts

____________ [2] Target coils and contacts

____________ [3] MOVs and transistors

____________ [4] Diodes and rectifiers

____________ [5] Resistors and capacitors

____________ [6] Relay taps and jumpers

____________ [7] Transformers and power supplies

(b) Trip contacts:

____________ [1] Contact callout tables

(c) Auxiliary relays:

____________ [1] References to breakers tripped and/or devices operated

____________ [2] Internal relay circuits as necessary

____________ (d) Relay terminals and connections

(b) Alarm circuits:

(1) Relays:

____________ (a) Coils

____________ (b) Contacts

____________ (2) Alarm cutout or reset switches

(3) Circuit switchers and motor-operated disconnect switches:

(a) Trip circuit:

(1) Protective relay circuits:

____________ (a) Internal coils and contacts

____________ (b) Target coils and contacts

____________ (c) MOV’s and transistors

____________ (d) Diodes and rectifiers

____________ (e) Resistors and capacitors

____________ (f) Relay taps and jumpers.

(2) Auxiliary relays:
Bulletin 1724E-300

Appendix A, Chapter 3

Page 89

____________ (a) Coils

____________ (b) Contacts

____________ (c) Miscellaneous devices

____________ (d) Spare device contacts

(3) Trip-blocking contacts:

____________ (a) Control switch contacts

____________ (b) Blocking relay coils and contacts

____________ (4) SCADA control contacts

(5) Contact callout tables:

____________ (a) Relay contacts

____________ (b) Switch contacts

(6) Switch nameplates (escutcheons):

____________ (a) Positions

(b) Close circuits:

____________ (1) Relay terminals and connections

(2) Close block circuits:

____________ (a) Relay coils and contacts

____________ (b) Switch contacts

____________ (3) SCADA control contacts

(c) Auxiliary circuits:

____________ (1) Motors

____________ (2) Alarm points

____________ (3) Miscellaneous

4. SCADA and/or Alarm Schematics

a. SCADA points:

____________ (1) Control

____________ (2) Indication

____________ (3) Metering

b. Annunciator(s):

____________ (1) Contacts and terminals

____________ (2) Auxiliary equipment and accessories

____________ c. Miscellaneous alarms

d. Circuit designations:

____________ (1) Each circuit identified per circuit schedule designation

____________ (2) Terminal conductors shown with color coding

____________ (3) Spare conductors indicated

____________ (4) Shield tape or ground indicated

____________ (5) circuit grounds indicated, if applicable

____________ e. SCADA point list

Q. MISCELLANEOUS EQUIPMENT YARD EXTERNAL CONNECTION

DIAGRAMS

Include the “General - for All Drawings” items.

____________ 1. Schematic Reference

2. Notes:

____________ a. Definition of terms

____________ b. Definition of symbols not shown on Legend sheet

____________ 3. Device Graphic Showing Terminals and Terminal Blocks
Bulletin 1724E-300

Appendix A, Chapter 3

Page 90

NOTE: In general, the internal detail is not required or is shown on device

manufacturer’s diagrams. The external cable connection is the important data to

be conveyed.

____________ 4. Terminal blocks with jumpers and external cable connections.
Bulletin 1724E-300

Appendix B, Chapter 3

Page 91

APPENDIX B

U.S. DEPARTMENT OF AGRICULTURE

RURAL UTILITIES SERVICE

SUBSTATION DESIGN SUMMARY

1 INTRODUCTION.................................................................................................... 94

1.1 General.............................................................................................................. 94

1.2 Basic Identification Data ..................................................................................... 94

1.3 Schedule ............................................................................................................ 94

1.4 Permits and Licenses.......................................................................................... 95

1.5 References......................................................................................................... 95

2 DESIGN CONSIDERATIONS................................................................................. 95

2.1 Initial and Ultimate Requirements........................................................................ 95

2.2 Site .................................................................................................................... 96

2.3 Environmental.................................................................................................... 96

3 DOCUMENTS......................................................................................................... 98

3.1 Authorizing Document for Design ....................................................................... 98

3.2 Distribution of Documents.................................................................................. 98

3.3 RUS Procedures................................................................................................. 98

3.4 Procurement..................................................................................................... 100

3.5 Drawing List or Drawing List Number............................................................... 100

3.6 Studies............................................................................................................. 100

4 PHYSICAL LAYOUT ........................................................................................... 100

4.1 Substation Type ................................................................................................ 100

4.2 Type of Design................................................................................................. 100

4.3 Circuit Connections .......................................................................................... 101

4.4 Distribution Substations.................................................................................... 101

4.5 Transmission Substations.................................................................................. 101

4.6 Switching Substations....................................................................................... 102

4.7 Bus Configuration............................................................................................. 102

4.8 Direct Stroke Shielding..................................................................................... 102

4.9 Insulators......................................................................................................... 102

4.10 Electrical Clearances ...................................................................................... 103

4.11 Bus and Electrical Connections........................................................................ 103

4.12 Rigid Buses.................................................................................................... 103

4.13 Strain Buses................................................................................................... 103

5 MAJOR EQUIPMENT........................................................................................... 104

5.1 Power Transformers......................................................................................... 104

5.2 Power Circuit Breakers..................................................................................... 104

5.3 Metal-Clad Switchgear ..................................................................................... 104

5.4 Substation Voltage Regulators........................................................................... 105

5.5 Shunt Capacitor Equipment............................................................................... 105

5.6 Air Switches..................................................................................................... 105

5.7 Surge Arresters ................................................................................................ 105

5.8 Automatic Circuit Reclosers.............................................................................. 106

5.9 Current Transformers....................................................................................... 106
Bulletin 1724E-300

Appendix B, Chapter 3

Page 92

5.10 Voltage Transformers..................................................................................... 106

5.11 Coupling Capacitors and Coupling Capacitor Voltage Transformers.................. 106

5.12 Mobile Units.................................................................................................. 107

6 SITE .................................................................................................................. 107

6.1 General............................................................................................................ 107

6.2 Drainage .......................................................................................................... 107

6.3 Earthwork........................................................................................................ 107

6.4 Roads .............................................................................................................. 107

6.5 Erosion Protection ............................................................................................ 108

6.6 Yard Surfacing Material.................................................................................... 108

6.7 Security Fence.................................................................................................. 108

7 STRUCTURES...................................................................................................... 108

7.1 Line Support Structures..................................................................................... 108

7.2 Equipment Support Structures........................................................................... 108

8 FOUNDATIONS ................................................................................................... 109

8.1 Soil.................................................................................................................. 109

8.2 Description of Concrete .................................................................................... 109

8.3 Description of Reinforcing Bar.......................................................................... 109

8.4 Oil Pollution Abatement.................................................................................... 109

8.5 Foundation Types............................................................................................. 109

9 GROUNDING....................................................................................................... 109

9.1 Soil Resistivity Measurements........................................................................... 109

9.2 Area of the Ground Grid.................................................................................... 110

9.3 Ground Fault Current........................................................................................ 110

9.4 Selection of Conductor Material......................................................................... 110

9.5 Safety Considerations........................................................................................ 111

9.6 Tolerable Touch and Step Voltages.................................................................... 111

9.7 Protective Surface Material and Reduction Factor............................................... 111

9.8 Design of a Substation Grounding System.......................................................... 111

10 INSULATED CABLES AND RACEWAYS........................................................... 111

10.1 Cables............................................................................................................ 111

10.2 Raceways....................................................................................................... 112

11 CORROSION........................................................................................................ 112

11.1 Rationale for the Provision (or Lack) of a Cathodic Protection System............... 112

11.2 Cathodic Protection System............................................................................. 112

12 PROTECTIVE RELAYING................................................................................... 112

12.1 General Philosophy......................................................................................... 112

12.2 Transmission Line Protection .......................................................................... 113

12.3 Transformer and Reactor Protection................................................................. 113

12.4 Bus Protection................................................................................................ 113

12.5 Breaker Failure Protection............................................................................... 113

12.6 Distribution Line Protection ............................................................................ 113

13 INSTRUMENTS, TRANSDUCERS, AND METERS.............................................. 114

14 SUBSTATION AUTOMATION............................................................................. 114

14.1 Functions to Be Performed.............................................................................. 114

14.2 Develop Architecture Philosophy..................................................................... 114

14.3 Architecture Definition.................................................................................... 114
Bulletin 1724E-300

Appendix B, Chapter 3

Page 93

14.4 Basic Elements............................................................................................... 114

15 AC AND DC AUXILIARY SYSTEMS................................................................... 115

15.1 AC System..................................................................................................... 115

15.2 DC System..................................................................................................... 115

16 CONTROL HOUSE............................................................................................... 116

16.1 Inside Dimensions .......................................................................................... 116

16.2 Basement....................................................................................................... 116

16.3 Foundation..................................................................................................... 116

16.4 Superstructure ................................................................................................ 116

16.5 Control Panels................................................................................................ 116

16.6 Cable Trays.................................................................................................... 117

16.7 Lighting......................................................................................................... 117

16.8 Air Conditioning Equipment............................................................................ 117

16.9 Heating Equipment......................................................................................... 117

17 COMMUNICATIONS........................................................................................... 117

17.1 Communications Channel Plan........................................................................ 117

17.2 Total Channel Capacity................................................................................... 117

17.3 Expansion Requirements or Future Capabilities................................................ 117

17.4 Communications Technology .......................................................................... 118
Bulletin 1724E-300

Appendix B, Chapter 3

Page 94

INTRODUCTION

1.1 GENERAL

1. This summary provides basic information on substation requirements and design.

2. The summary will be updated as the project progresses from initial design to in-service status.

In its final form it will be, with supporting and reference documents, a complete record of the

substation.

1.2 BASIC IDENTIFICATION DATA

1. Substation Name 

2. Cooperative’s Designation and Name 

3. Location 

4. Summary Prepared by 

Date 

Revision “A” Prepared by 

Date 

(As many listings as necessary. Whenever a revision is made, a notation should be entered

in the left-hand margin adjacent to the item revised.)

1.3 SCHEDULE

 Proposed or Record

 Date

1.3.1 Pre-Design (identify documentation of each item for record) _______________

a. Environmental Assessment or Environmental Report _______________

b. Site purchase and title clearance _______________

c. Topographical survey _______________

d. Ambient noise level survey _______________

e. Surrounding land use survey _______________

f. Soil borings _______________

g. Soil resistivity measurements _______________

1.3.2 Design

a. One-line diagram and general layout for cooperative’s approval _______________

b. Detailed design for cooperative’s approval (list individual areas

such as foundations, structures, electrical below grade, electrical above

grade, and protective relaying if separate submittals are required) _______________

c. Design complete _______________

1.3.3 Procurement (itemize as listed below for each set of equipment, material, and hardware)

a. Specification for cooperative’s approval _______________

b. Bid invitation _______________

c. Pre-bid meeting with vendors or contractors (sometimes

advantageous for major equipment or construction) _______________
Bulletin 1724E-300

Appendix B, Chapter 3

Page 95

d. Bids received _______________

e. Bid opening (usually construction only) _______________

f. Evaluation of bids _______________

g. Pre-award meeting (sometimes advantageous with major equipment

 or construction) _______________

h. Contract award _______________

i. Delivery (equipment, material, or hardware) _______________

1.3.4 Construction

a. Begin construction _______________

b. Complete site grading _______________

c. Complete drainage _______________

d. Complete roadways _______________

e. Complete fence _______________

f. Begin foundations, conduit, and grounding _______________

g. Complete below grade _______________

h. Begin above grade _______________

i. Complete outdoor yard _______________

j. Complete control house _______________

k. Complete testing (list documents) _______________

l. Complete inspection (list documents) _______________

m. In service _______________

1.4 PERMITS AND LICENSES

List all permits and licenses that will be required prior to and during construction. 

 

 

 

1.5 REFERENCES

1. Power requirements study (identify) _______________

2. Two-Year Work Plan (identify) _______________

3. Conceptual one-line diagram (identify) _______________

2 DESIGN CONSIDERATIONS

2.1 INITIAL AND ULTIMATE REQUIREMENTS

1. Nominal Operating Voltages (itemize as listed below for each voltage):

a. Voltage ____________ kV

b. Design BIL____________ kV

c. Connection (delta or wye) ____________

d. Phase rotation ____________

e. Phase displacement with respect to other voltages (leads or lags) ______________ kV by

____________
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2. Capacity:

a. Voltage Transformations (itemize as listed below for each transformation):

(1) High Voltage/Low Voltage ______/_______ kV:

(a) Initial Capacity ____________ MVA

(b) Ultimate Capacity ____________ MVA

(2) High Voltage/Low Voltage ______/_______ kV:

(a) Initial Capacity ____________ MVA

(b) Ultimate Capacity ____________ MVA

b. Circuit Connections (itemize as listed below for each connection):

(1) Voltage _________________ kV

(a) Initial Quantity ____________

(b) Final Quantity _____________

(2) Voltage _________________ kV

(a) Initial Quantity ____________

(b) Final Quantity _____________

c. Bus Configurations (itemize as listed below for each bus):

(1) Nominal Bus Voltage:

(a) Initial Configuration __________________

(b) Ultimate Configuration (single bus, sectionalized bus, main and transfer bus, ring

bus, breaker-and-a-half, double breaker-double bus) _______________________

(2) Nominal Bus Voltage:

(a) Initial Configuration __________________

(b) Ultimate Configuration (single bus, sectionalized bus, main and transfer bus, ring

bus, breaker-and-a-half, double breaker-double bus) _______________________

d. Current-Carrying Requirements (itemize as listed below for each bus and circuit

connection):

(1) Bus or circuit connection description ________________________

(2) Nominal voltage ____________ kV

(3) Ampacity:

(a) Continuous ____________ amperes

(b) 24-hour temporary ____________ amperes

e. Ultimate Power Supply Fault Conditions:

(1) Three-phase fault ____________ amperes

(2) Phase-to-phase fault ____________ amperes

(3) Phase-to-ground fault ____________ amperes

f. Maximum Permissible Fault Clearing Time ____________ seconds

2.2 SITE

State any unusual constraints imposed on the design because of site characteristics.

2.3 ENVIRONMENTAL

1. State that design is in accordance with Environmental Assessment (identify) or Environmental

Report (identify).

2. Describe property and adjacent property including existing land use.

3. State any other uses in addition to substation (such as storage).

4. Describe, in general, any design measures taken to enhance appearance.

5. State the necessity for any unusual cost items related to public safety.
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6. State the rationale for noise contribution.

7. State the expected electrostatic and electromagnetic effects.

8. State the rationale for effluent design. Recommend that a design be made for a plan of action

to prevent pollution if this is so indicated.

2.3.1 Weather

a. State any unusually severe possible local conditions that the substation is not designed to

withstand.

b. State what design measures have been taken with respect to any special local condition.

2.3.2 Temperatures

a. Average annual temperature:

(1) Maximum ____________ oC (____________ oF)

(2) Minimum ____________ oC (____________ oF)

b. Highest recorded temperature ____________ oC (____________oF)

c. Lowest recorded temperature ____________ oC (____________oF)

2.3.3 Wind and Ice Loading (itemize as listed below for line support structures, equipment support

structures, and conductors)

a. Wind:

1. Velocity ____________ km/hr (____________ mph)

2. Safety factor ____________

3. Gusts ____________ km/hr (____________ mph)

4. Safety factor ____________

b. Ice:

1. Thickness ____________ cm (____________ in.)

2. Safety factor ____________

2.3.4 Precipitation

a. Design rainfall:

1. Amount ____________ cm/hr (____________ in./hr)

2. Period ____________ hours

3. Frequency of storm occurrence ____________

b. Design snowfall:

1. Maximum drift depth ____________ m (____________ ft)

c. Electrical storms:

1. Isokeraunic level ____________ thunderstorm days per year

d. Humidity:

State design measures.

2.3.5 Altitude Above Mean Sea Level ____________ m (____________ ft)

2.3.6 Seismic Risk Zone ________________
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2.3.7 Wildlife Protection

State any unusual measures required.

2.3.8 Airborne Foreign Material Protection

State materials protecting against.

3 DOCUMENTS

3.1 AUTHORIZING DOCUMENT FOR DESIGN

3.2 DISTRIBUTION OF DOCUMENTS Itemize as listed below for each document and recipient.

(See Table 3-2 for Typical Document Distribution List.)

1. Document Description _____________________________________________________

__ ____________________________________________________________________

2. Name and Address of Recipient ______________________________________________

__ ____________________________________________________________________

__ ____________________________________________________________________

3. Number of Copies Spec _______ , Full-Size Drawings _______ , Half-Size Drawings _______

3.3 RUS PROCEDURES (To be checked with RUS)

1. Name and Address of RUS General Field Representative ____________________________

______________________________________________________________________

______________________________________________________________________
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Table 3-2: Typical Document Distribution List

Distribution List

Cooperative’s

Environmental

Report

Feasibility

Studies

Technical

Studies

Procedures

Manual

Design

Manual

Equipment

Contract

Materials

Contract

Construction

Contract

Permits

Drawings

Owner

General Manager X X X *

Chief Engineer X X X X X X X X X *

Legal X X X X X X X

Design Engineer X X X X X X X X X

Owner’s Field Representative X X X X X X X

File X X X X X X X X X X

Engineer X

Project Manager X X X X X X X * *

Design Engineer X X X X X X X X X X

File X X X X X X X X X X

Resident Manager X X X X X X X

Inspector X X X X X

Contractors

C1 * * * * *

C2 * * * * *

C3 * * * * *

C4 * * * * *

C5 * * * * *

Approving Agencies

RUS X X * X

County/City Engineer * * * * * *

Interconnecting Utility X X * * * * *

Property Holder * *

* As Required.
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3.4 PROCUREMENT

1. Major Equipment (itemize as listed below for each major piece of equipment, contract, or P.O):

a. Description of Equipment _________________________________________

b. Name and Address of Manufacturer _______________________________________

c. Contract number ____________

d. Purchase order number ____________

2. Construction Contracts (itemize as listed below for each contract):

a. Description of contract 

 

b. Name and address of contractor

 

 

 

c. Contract number ________________________

d. Purchase order number _______________________

3. Equipment, Materials, and Hardware (itemize as listed below for each item, contract, or P.O):

a. Description of item 

 

 

b. Name and address of manufacturer

 

 

 

c. Purchase order number _______________

3.5 DRAWING LIST OR DRAWING LIST NUMBER

Provide list of drawings or drawing list number. Indicate contracts, purchase orders, etc., each drawing is

part of or referenced.

3.6 STUDIES

Describe the studies that are required.

4 PHYSICAL LAYOUT

4.1 SUBSTATION TYPE (distribution, transmission, switching)

 

4.2 TYPE OF DESIGN (cooperative’s standard, packaged, custom)

 
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4.3 CIRCUIT CONNECTIONS Itemize as listed below for each connection.

1. Overhead Circuits:

a. Nominal voltage ____________ kV

b. Quantity ____________

c. Conductor size, type, and material ____________

d. Pull-off elevation ____________ m (____________ ft)

e. Maximum tension ____________ N (____________ lb)

(1) Temperature ____________ oC (____________ oF)

(2) Ice thickness ____________ cm (____________ in.)

(3) Wind velocity ____________ km/hr (____________ mph)

f. Shield wires:

(1) Quantity of shield wires per connection ____________

(2) Wire size, type, and material _____________________

(3) Pull-off elevation ____________ m (____________ ft)

(4) Maximum tension (at same conditions as phase conductors) ____________

N (____________ lb)

2. Underground Circuits:

a. Nominal voltage ____________ kV

b. Quantity ____________

c. Conductor size, type, material, and insulation _____________________________

4.4 DISTRIBUTION SUBSTATIONS

1. Provisions for Mobile Transformer (yes or no) ____________

2. Provisions for Mobile Substation (yes or no) ____________

3. Provisions for Future Addition of (describe) _______________ 

 

4. Provisions for Source Voltage Change (yes or no) ____________

a. Initial voltage ____________ kV

b. Ultimate voltage ____________ kV

c. Change of (describe) _________________

5. Provisions for Load Voltage Change (yes or no) ____________

a. Initial voltage ____________ kV

b. Ultimate voltage ____________ kV

c. Change of (describe) 

 

4.5 TRANSMISSION SUBSTATIONS (only)

1. Provisions for Future Addition of (describe) 

 

2. Provisions for Source Voltage Change (yes or no) ____________

a. Initial voltage ____________ kV

b. Ultimate voltage ____________ kV

c. Change of (describe) 

 

3. Provisions for Load Voltage Change (yes or no) ____________

a. Initial voltage ____________ kV
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b. Ultimate voltage ____________ kV

c. Change of (describe) 

 

4.6 SWITCHING SUBSTATIONS (only)

1. Provisions for Future Addition of (describe) 

 

2. Provisions for Voltage Change (yes or no) ______________________

a. Initial voltage ____________ kV

b. Ultimate voltage ____________ kV

c. Change of (describe) 

 

4.7 BUS CONFIGURATION Itemize as listed below for each bus.

1. Initial:

a. Nominal bus voltage ____________ kV

b. Configuration (single bus, sectionalized bus, main and transfer bus, ring bus, breakerand-a-half, double breaker-double bus) 

2. Ultimate (if different from initial):

a. Nominal bus voltage ____________ kV

b. Configuration (describe) 

 

4.8 DIRECT STROKE SHIELDING

1. Shielding Measures (rods, wires, masts) (describe)

___________________________________________________________________________

2. Shielding Angles:

a. Angle from vertical for single rod, wire, or mast ____________o

b. Angle from vertical for adjacent rods, wires, or masts ____________o

4.9 INSULATORS Itemize as listed below for each voltage.

1. Apparatus Insulators:

a. Nominal voltage ____________ kV

b. Type (cap and pin or post) ____________

c. BIL ____________ kV

d. Color ____________

e. Cantilever strength ____________ N (____________ lb)

f. NEMA TR No. (or other description) 

 

2. Suspension Insulators:

a. Nominal voltage ____________ kV

b. Quantity per string ____________

c. Color ____________

d. M-E strength ____________ N (____________ lb)

e. ANSI Class (or other description) 
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4.10 ELECTRICAL CLEARANCES Itemize as listed below for each voltage.

1. Nominal voltage ____________ kV

 Rigid Non-Rigid

Conductors Conductors

2. Minimum Metal-to-Metal _____ cm (_____ in.) _____ cm (_____ in.)

3. Minimum Phase to _____ cm (_____ in.) _____ cm (_____ in.)

Grounded Parts

4. Minimum Phase to _____ m (_____ ft) _____ m (_____ ft)

Substation Grade

5. Minimum Phase to _____ m (_____ ft) _____ m (_____ ft)

Substation Roadway

6. Centerline-to-Centerline _____ m (_____ ft) _____ m (_____ ft)

Phase Spacing

4.11 BUS AND ELECTRICAL CONNECTIONS Itemize as listed below for each case.

1. Nominal Voltage ____________ kV

2. Type of Connection (describe) _______________________________________________

3. Rigid Conductors (clamp, bolted, compression, welded) ___________________________

4. Non-Rigid Conductors (clamp, compression, welded) _____________________________

5. Fasteners (describe) ________________________________________________________

4.12 RIGID BUSES (itemize as listed below for each bus)

1. Conductor Size, Type, and Material ___________________________________________

2. Design Short Circuit Current (three-phase symmetrical) ____________ rms amperes

3. Wind and Ice Loading

4. Support Insulator Spacing ____________ m (____________ ft)

5. Factor of Safety for Support Insulators ____________

6. Maximum Conductor Sag Without Ice ____________

7. Maximum Conductor Sag With Ice ____________

8. Measures for Prevention of Aeolian Vibration ___________________________________

9. Provisions for Conductor Expansion ___________________________________________

4.13 STRAIN BUSES Itemize as listed below for each bus.

1. Conductor Size, Type, Stranding, and Material ______________________________________

2. Wind and Ice Loading

3. Span Length ____________ m (____________ ft)

4. Factor of Safety for Suspension Insulators ____________

5. Sag and Tension at Maximum Loading Conditions ____________ m (____________ ft) sag at

____________ N (____________ lb) tension

6. Sag and Tension at 25oC (77oF) ____________ m (____________ ft) sag at ___________ N

(____________ lb) tension

7. Sag and Tension at 70oC (167oF) ____________ m (____________ ft) sag at __________ N

(____________ lb) tension
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5 MAJOR EQUIPMENT

Itemize as listed below for each different component.

5.1 POWER TRANSFORMERS

1. Type (auto, multi-winding, 3-phase, 1-phase) _________________________

2. Quantity ____________

3. Dielectric (oil, air, or gas) ________________

4. Rating ________/ ________/ ________ MVA

5. Cooling (OA, OA/FA, OA/FA/FA, OA/FOA, OA/FA/FOA, OA/FOA/FOA) ____________

6. Average Winding Temperature Rise (55oC, 65oC) ____________

7. Primary Voltage ____________ kV

a. No-load taps ____________

8. Secondary Voltage ____________ kV

a. No-load taps ____________

9. Tertiary Voltage ____________ kV

a. No-load taps ____________

10. Load-Tap-Changer (LTC):

a. Percentage above and below nominal voltage ____________

b. Winding (primary or secondary) ____________

11. BIL:

a. Primary winding ____________ kV

b. Secondary winding ____________ kV

c. Tertiary winding ____________ kV

5.2 POWER CIRCUIT BREAKERS

1. Type (dead tank or live tank) ____________

2. Quantity____________

3. Interrupting Medium (oil, gas (SF6), vacuum)____________

4. Nominal Voltage____________ kV

5. Maximum Voltage ____________ kV

6. Rated Voltage Range Factor (K)____________

7. Continuous Current ____________ rms amperes

8. Short-Circuit Current at Rated Maximum Voltage ____________ rms amperes

9. Maximum Symmetrical Interrupting Capability ____________ rms amperes

10. 3-Second Short Time Current Capability ____________ rms amperes

11. Closing and Latching Capability ____________ rms amperes

12. Interrupting Time ____________ cycles

13. Type of Operating Mechanism (solenoid, motor, pneumohydraulic, pneumatic, motor-charged

spring, manual-charged spring, manual) _________________________________

14. Control Power Voltage ____________ VAC ____________ VDC

15. Auxiliary Power Voltage ____________ VAC

5.3 METAL-CLAD SWITCHGEAR

1. Nominal Voltage ____________ kV
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2. Indoor or Outdoor ____________ , Sheltered Aisle_____________________

3. Switching Scheme (describe) 

____________________________________________________________________________

4. Continuous Current Bus ____________ amperes, Feeders ______________ amperes

5. Maximum RMS Momentary Current ____________ kA, ______________ MVA

6. Circuit Breaker Interrupting Capability ____________ amperes

7. Circuit Exits Underground ________________ , Overhead _____________

5.4 SUBSTATION VOLTAGE REGULATORS

1. Type (step or induction, single- or three-phase) _____________________

2. Quantity ____________

3. Nominal Voltage ____________ kV

4. Rating ____________ kVA

5. Percentage Regulation + ____________%, – ____________%

5.5 SHUNT CAPACITOR EQUIPMENT

1. Type (open rack or housed) ___________________

2. Quantity ____________

3. Nominal Voltage ____________ kV

4. Bank Rating ____________ kVAR

5. Individual Units:

a. Voltage ____________ kV

b. Rating ____________ kVAR

6. Connection (delta, wye, grounded wye, double wye) _______________________________

5.6 AIR SWITCHES

1. Type (disconnecting, grounding, horn-gap, interrupter, selector) ______________________

2. Quantity ____________

3. Construction (vertical break, double break, tilting insulator, side break, center break, vertical

reach) ____________________________________________________________________

4. Operating Mechanism (hook stick, manual mechanism, motor mechanism) _____________

5. Poles (single or three) ____________

6. Nominal Voltage ____________ kV

7. Continuous Current ____________ amperes

8. Momentary Current ____________ amperes

9. Interrupting Current ____________ amperes

5.7 SURGE ARRESTERS

1. Type (station, intermediate, distribution) __________________________

2. Quantity ____________

3. Voltage Rating ____________ kV-Duty Cycle, ____________ kV MCOV

4. Nominal System Voltage ____________ kV

5. System Grounded _______________ , Ungrounded ________________

6. For Protection of (describe) ___________________________________________
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5.8 AUTOMATIC CIRCUIT RECLOSERS

1. Quantity ____________

2. Nominal Voltage ____________ kV

3. Continuous Current ____________ amperes

4. Interrupting Current ____________ amperes

5. Single- or Three-Phase ____________

6. Interrupting Medium (oil, vacuum, gas (SF6)) ________________

7. Control (Hydraulic or electronic) _______________

8. Coil Tripping (series, non-series) _______________

9. Closing (spring, solenoid, motor) ____________ ___

10. Minimum Tripping Current ____________ amperes

11. Operational Sequence to Lockout (1-A, 3-B) _______________

5.9 CURRENT TRANSFORMERS

1. Type (bar, window, bushing, other) ____________

2. Quantity ____________

3. Nominal System Voltage ____________ kV

4. BIL ____________ kV

5. Rated Primary to Secondary Current Ratio(s)________________

6. Secondary Winding Configuration (single, dual, multi-ratio) ________________

7. Accuracy (metering or relaying) ________________

8. Accuracy Class at Standard Burdens ________________

9. Continuous – Thermal – Current Rating Factor __________________

10. Short-Time Mechanical and Thermal Current Ratings ___________________

5.10 VOLTAGE TRANSFORMERS

1. Type (cascade, grounded neutral, insulated neutral, single high-voltage line terminal, double

high-voltage line terminal, etc.) ___________________________

2. Quantity ____________

3. Nominal System Voltage ____________ kV

4. BIL ____________ kV

5. Ratio(s) ____________

6. Accuracy Class at Standard Burdens ____________

7. Thermal Burden Rating ____________ VA

5.11 COUPLING CAPACITORS AND COUPLING CAPACITOR VOLTAGE

TRANSFORMERS

1. Type (CC or CCVT) ____________

2. Quantity ____________

3. Nominal System Voltage ____________ kV

4. BIL ____________ kV

5. Capacitance ____________ pico farads

6. Carrier Accessories (yes or no) ____________

7. Voltage transformer (yes or no) ____________
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a. Ratio(s) ____________

b. Accuracy Class at Standard Burdens ____________________

c. Thermal Burden Rating _____________________

5.12 MOBILE UNITS

1. Type (transformer, substation) ____________

2. Quantity ____________

3. Primary Voltage ____________ kV

4. Secondary Voltage ____________ kV

5. Capacity ____________ MVA

6. Accessories (list and describe) 

 

 

6 SITE

6.1 GENERAL

1. Yard Type (flat, sloped, stepped) ________________________

2. Nominal Finished Grade Elevation(s) ____________ m (____________ ft) with

____________% slope

3. Topographical Drawing Reference ______________________

4. Soil Boring Reference _______________________

6.2 DRAINAGE

1. Type of System (surface or closed) ____________

2. Design Basis (see Chapter 6, Section 6.4)

3. Time for Runoff from Remotest Part of Drainage Area ____________ hours

6.3 EARTHWORK

1. Excess Top Soil ____________ m3 (____________ yd3)

2. Fill Required ____________ m3 (____________ yd3)

3. Earth to Be Moved Exclusive of Excess Top Soil ____________ m3 (___________ yd3)

6.4 ROADS Itemize as listed below for each access road, interior road, and railroad.

1. Length ____________ m (____________ ft)

2. Width ____________ m (____________ ft)

3. Maximum Grade ____________%

4. Minimum Inside Curve Radius ____________ m (____________ ft)

5. Base Course ____________

6. Wearing Course ____________

7. Maximum Equipment Load ____________ kg/axle (____________ lb/axle)
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6.5 EROSION PROTECTION

State basic description.

6.6 YARD SURFACING MATERIAL

1. Material:

a. Type ____________

b. Size ____________

2. Material Placement:

a. Area

b. Layer depth ____________ cm (____________ in.)

6.7 SECURITY FENCE

1. Height ____________ m (____________ ft)

2. Fabric Gauge ____________

3. Fabric Material ____________

4. Gates (itemize as listed below for each size gate):

a. Size ____________ m (____________ ft)

b. Quantity ____________

5. Depth of Post Footing Holes ____________ m (____________ ft)

7 STRUCTURES

7.1 LINE SUPPORT STRUCTURES

1. Material 

2. Protective Coating or Treatment 

3. Loading Criteria:

a. Conductors ______________ N (_____________ lb) per phase

b. Shield wires ____________ N (____________ lb) per wire

c. Equipment weight ____________ kg (____________ lb)

d. Wind and ice loads (see Sections 2.3.3)

e. Seismic (describe) 

 

4. Overload Factor ________________________

5. Unit Stress Limit ________________________

6. Deflection Limits ________________________

7. Fasteners (describe) 

 

7.2 EQUIPMENT SUPPORT STRUCTURES

1. Material ________________________

2. Protective Coating or Treatment ________________________

3. Loading Criteria:

a. Equipment weight ____________ kg (____________ lb)
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b. Short circuit force ____________ N/m (____________ lb/ft)

c. Wind and ice loads (see Sections 2.3.3)

d. Seismic (describe) 

 

4. Unit Stress Limit ________________________

5. Deflection Limits ________________________

6. Rigidity Considerations 

7. Fasteners (describe) 

 

8 FOUNDATIONS

8.1 SOIL

1. Type 

2. Allowable Soil Bearing Pressure ____________ N/m2 (____________ psf)

3. Describe Other Soil Capability Limitations 

4. Depth Below Grade to Groundwater ____________ m (____________ ft)

8.2 DESCRIPTION OF CONCRETE

1. Type 

2. Minimum 28-Day Compressive Strength ____________ N/cm2 (____________ psi)

3. Depth Below Grade to Withstand Frost ____________ m (____________ ft)

8.3 DESCRIPTION OF REINFORCING BAR

Describe the reinforcing bar used in each type of foundation.

8.4 OIL POLLUTION ABATEMENT

Describe methods for oil pollution abatement.

8.5 FOUNDATION TYPES

Describe each type of foundation (drilled shaft, spread footing, slab) and its function.

9 GROUNDING

9.1 SOIL RESISTIVITY MEASUREMENTS

1. Data from soil testing on (date) .

9.1.1 Uniform Soil Assumption

1. Mathematical average of the measured apparent resistivity data, ρ = ohm-meter
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9.2 AREA OF THE GROUND GRID

1. Describe geometric shape of ground grid including dimensions.

2. Calculated total ground grid area, A = m

2

9.3 Ground Fault Current

9.3.1 Maximum Symmetrical rms Value of Zero Sequence Fault Current (single phase-to-ground),

Io = Amps

9.3.2 Initial rms Symmetrical Ground Fault Current, If = Amps

9.3.3 Symmetrical Grid Current, Ig = Amps

9.3.4 Determined Split Factor:

1. Substation ground resistance, Rg = ohms

2. Split Factor, Sf = 

9.3.5 Determine Decrement Factor

1. Time duration of fault, tf = seconds

2. Dc offset, Ta = seconds

3. Decrement factor, Df = 

9.3.6 Maximum Grid Current, IG = Amps

9.3.7 Asymmetrical Fault Current, IF = Amps

9.4 SELECTION OF CONDUCTOR MATERIAL

1. Material Cu _______________ Other _________________

9.4.1 Area of Conductor

1. Area of Conductor:

a. Maingrid Akcmil = ______________ kcmil

b. Perimeter Akcmil = ______________ kcmil

c. Risers Akcmil = _________________ kcmil

2. Length of Conductor:

a. Main grid _______________

b. Perimeter _______________

c. Risers __________________

9.4.2 Ground Rods:

1. Diameter 

2. Length 
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3. Quantity 

9.5 SAFETY CONSIDERATIONS

9.5.1 Rms magnitude of the current through the body, IB = Amps

9.6 TOLERABLE TOUCH AND STEP VOLTAGES

1. Maximum tolerable step voltages, Estep = volts

2. Maximum tolerable touch voltages, Etouch = volts

9.7 PROTECTIVE SURFACE MATERIAL AND REDUCTION FACTOR

1. Type of protective surface material ____________________________

2. Resistivity of protective surface material, ρs = ohm-meter

3. Reflection factor, K= ________________

4. Reduction factor, Cs = ___________________

9.8 DESIGN OF A SUBSTATION GROUNDING SYSTEM

9.8.1 Grid Design 

 

9.8.2 Calculated Design Mesh Voltage

1. Calculate total length of grid conductor LR = meter

2. Calculated total length ground rod LC = meter

3. Calculated Design Mesh Voltage, Em = volts

9.8.3 Calculated Design Step Voltage, ES = volts

9.8.4 Ground Potential Rise, VGPR = volts

10 INSULATED CABLES AND RACEWAYS

10.1 CABLES Itemize as listed below for each type of cable.

1. Type (control or power) ____________

2. Voltage Rating ____________ volts

3. Conductor Size, Type, and Material

4. Number of Conductors ____________

5. Quantity ____________ m (____________ ft)

6. Insulation:

a. Type ________________________

b. Thickness ____________ mils

7. Jacket:

a. Type ________________________

b. Thickness over each conductor ____________ mils

c. Thickness over entire cable ____________ mils
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10.2 RACEWAYS Itemize as listed below for each type of raceway.

1. Conduit:

a. Material ___________________________

b. Size ____________ cm (____________ in.)

2. Duct Bank:

a. Size

(1) Width ____________ m (____________ ft)

(2) Depth ____________ m (____________ ft)

(3) Number of conduits:

(a) Width ____________

(b) Depth ____________

(4) Size of conduits ____________ cm (____________ in.)

3. Cable Trench

a. Type (concrete block, cast-in-place concrete, or precast concrete)

b. Width ____________ cm (____________ in.)

c. Depth ____________ cm (____________ in.)

11 CORROSION

11.1 STATE RATIONALE FOR THE PROVISION (OR LACK) OF A CATHODIC

PROTECTION SYSTEM

11.2 CATHODIC PROTECTION SYSTEM

1. Summary of Soil Resistivity Survey

 

 

 

2. Summary of pH Survey

 

 

 

3. Basic Description of Protection System

 

 

 

12 PROTECTIVE RELAYING

12.1 GENERAL PHILOSOPHY

State the general philosophy of the protective relaying systems: coordination required with other parts of

the system, expected fault currents for various conditions, speed of interruption sought for various cases,

etc.
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12.2 TRANSMISSION LINE PROTECTION Itemize as listed below for each line.

1. Line Destination or Description 

2. Nominal Voltage ____________ kV

3. Protection Scheme (phase comparison, directional comparison, direct underreach, permissive

underreach, permissive overreach, overcurrent; describe) 

____________________________________________________________________________

 

4. Automatic Reclosing (yes or no; describe) 

5. Relays (list) 

6. Communication Channel (Power Line Carrier, Microwave, Fiber Optic, Leased Line)

____________________________________________________________________________

12.3 TRANSFORMER AND REACTOR PROTECTION Itemize as listed below for each

transformer and reactor.

1. Transformer or Reactor Number or Description ______________________________________

2. Nominal Voltages (Primary/tertiary/secondary) ___________/ ___________/ ___________ kV

3. Protection Scheme (differential, sudden pressure, directional phase distance, ground

overcurrent; describe) 

____________________________________________________________________________

4. Relays (list) 

____________________________________________________________________________

12.4 BUS PROTECTION Itemize as listed below for each bus.

1. Bus Number or Description _________________________________________________

2. Nominal Voltage ____________ kV

3. Protection Scheme (current differential, voltage differential; describe) 

 

4. Relays (list) 

 

12.5 BREAKER FAILURE PROTECTION

1. Where applied (describe) 

 

2. Relays (list) 

 

12.6 DISTRIBUTION LINE PROTECTION Itemize as listed below for each line.

1. Line Destination or Description 

2. Nominal Voltage ____________ kV

3. Protection Scheme (overcurrent relaying, automatic circuit reclosers, sectionalizers, fuses;

describe) 

4. Relays and Equipment (list) 
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13 INSTRUMENTS, TRANSDUCERS, AND METERS

Describe metering systems and list equipment for each system.

14 SUBSTATION AUTOMATION

Define the application by completing the following information:

14.1 FUNCTIONS TO BE PERFORMED

Describe the functions to be performed:

a. Automatic control

b. Supervisory control

c. Monitoring

d. Human - machine

14.2 DEVELOP ARCHITECTURE PHILOSOPHY

Justify whether a proprietary or open system is needed.

14.3 ARCHITECTURE DEFINITION

1. Top layer—user interface where data and control prerogatives are presented to the end user.

2. Intermediate layer—implemented with discrete elements or subsystems.

3. Bottom layer—electrical power substation and field devices (transformers, breakers, switches,

etc).

14.4 BASIC ELEMENTS

1. Will a local substation host processor be used (single or multiple computers)? Describe

rationale.

2. Describe the type of redundancy that is needed for this application.

3. Describe any Intelligent Electronic Devices (IEDs) to be used:

a. Function

b. Communications medium

c. Protocols supported

d. Data acquisition method

4. Will a data concentrator be used? Describe its purpose and functions.

5. If a LAN is used, describe:

a. What access method will be used (CSMA/CD, token ring, token bus, or FDDI)? Develop

rationale.

b. What is the expected load of the network?

c. Do any functions require a deterministic access method? Describe.

d. What is the desired data rate?

e. Define the physical locations of nodes or communicating devices.

f. Describe the physical media that will be used (coaxial cable, UTP, or optical fiber).

g. Describe any serial data interfaces to be used (RS-232, RE-422/423 or RS-485). Define

type, location, and purpose.
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6. What is the communications protocol(s) being utilized (IEC 970-5, DNP 3.0, MODBUS,

MMS, ASCII, Landis & Gyr 8979, or other)?

15 AC AND DC AUXILIARY SYSTEMS

15.1 AC SYSTEM

1. Connected AC Load ____________ kVA

2. Overall Demand Factor ____________%

3. Auxiliary Transformer:

a. Rating ____________ kVA

b. Voltage (primary/secondary) ____________/ ____________ kV

4. Normal Source (describe) 

 

5. Alternative Source (describe) 

 

6. Auxiliary System Voltage (480/277 volts, wye-connected, three-phase, four-wire; 208/120

volts, wye-connected, three-phase, four-wire; 240/120 volts, delta-connected, three-phase, fourwire; 240/120 volts, open delta-connected, three-phase, four-wire; 240/120 volts, single-phase,

three-wire) 

 

7. Transfer Switch (describe) 

 

8. Asymmetrical Fault Current at Main Panelboard or Switchboards ___________ amperes

9. Panelboards and Switchboards (describe) 

 

 

10. Outdoor Lighting:

a. Objective (describe) 

 

b. Luminaires (describe) 

 

c. Switching method (describe) 

15.2 DC SYSTEM

1. DC System Loads (list) 

 

2. Nominal Voltage ____________ volts

3. Battery:

a. Cell type _______________

b. Ampere-hours ____________

c. Number of cells ____________

4. Battery Charger (describe) 

 

a. DC amps ___________________
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16 CONTROL HOUSE

16.1 INSIDE DIMENSIONS

1. Length ____________ m (____________ ft)

2. Width ____________ m (____________ ft)

3. Clear Height ____________ m (____________ ft)

16.2 BASEMENT (yes or no) ____________

16.3 FOUNDATION

1. Footings:

a. Width ____________ cm (____________ in.)

b. Depth ____________ m (____________ ft)

c. Depth below grade ____________ m (____________ ft)

2. Foundation Walls:

a. Type (cast-in-place concrete or concrete block)

b. Perimeter Insulation (yes or no) ____________

(1) Type ________________________

(2) Thickness ____________ cm (____________ in.)

(3) Location (inside or outside of walls) 

3. Floor:

a. Thickness ____________ cm (____________ in.)

b. Reinforcing (describe) 

 

c. Cast-in-Concrete Cable Trench (yes or no) (describe) 

 

16.4 SUPERSTRUCTURE

1. Type (pre-engineered metal or concrete block) 

2. Roof Type (precast, prestressed concrete panels, or steel joists and steel decks) 

 

3. Doors (itemize as listed below for each door size):

a. Size ____________ cm (____________ in.) x ____________ cm (____________ in.)

b. Quantity ____________

4. Windows (itemize as listed below for each window size)

a. Size ____________ cm (____________ in.) x ____________ cm (____________ in.)

b. Quantity ____________

16.5 CONTROL PANELS

1. Type (single, double, or duplex) 

2. Function (list each panel) 

3. Size ____________ cm (____________ in.) x ____________ cm (____________ in.)
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16.6 CABLE TRAYS

1. Size ____________ cm (____________ in.)

2. Method of Support (describe) 

 

16.7 LIGHTING

1. Average illumination ____________ lumens/m2 (lumens/ft2)

2. Luminaires (describe) 

 

3. Emergency lighting (describe) 

16.8 AIR CONDITIONING EQUIPMENT

1. Number of units _________ ___

2. Type of units _______________

3. Rating _____________________

16.9 HEATING EQUIPMENT

1. Number of units ____________

2. Type of units ____________

3. Rating ____________

17 COMMUNICATIONS

17.1 COMMUNICATIONS CHANNEL PLAN

Completing the following information for each channel needed:

1. Application (relaying, SCADA, telemetering, voice, other)

2. Bandwidth or capacity (may be expressed in bits/second)

3. End-to-end channel delay constraints

4. Remote terminating point(s)

5. Reliability/redundancy requirements

17.2 TOTAL CHANNEL CAPACITY

Define total channel capacity.

17.3 EXPANSION REQUIREMENTS OR FUTURE CAPABILITIES

Define expansion requirements or future capabilities that need to be accommodated.
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17.4 COMMUNICATIONS TECHNOLOGY

Select a communications technology based on the parameters defined above:

1. Power line carrier

2. Audio tone

3. Carrier or audio tone on shield wire

4. Microwave (analog, digital, or MAS)

5. Fiber optics

6. Wire lines

7. Satellite
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CHAPTER 4

PHYSICAL LAYOUT

4.1 INTRODUCTION

This chapter presents general information concerning the design of the substation physical arrangement.

It describes various types of substations, illustrates typical layouts, and presents guidelines to be used

during detailed design. Information concerning insulation, electrical clearances, bare conductors,

substation bus design, and the application of mobile transformers and mobile substations is included.

4.2 LAYOUT CONSIDERATIONS

4.2.1 Initial Design Parameters

A careful analysis of basic parameters establishing the purposes and design criteria for the substation has

to precede the detailed design. Much of this information can be found on the Substation Design

Summary form of Appendix B to Chapter 3. In addition, circuit quantities, configurations, and ratings;

system and equipment protective relay schemes; the necessity for specialized equipment (such as

capacitor banks, current-limiting reactors, and neutral grounding devices); details of surge protection

equipment; and requirements for direct stroke protection should be considered.

4.2.2 Selection of Switching Scheme

The power system as a whole has to be considered when deciding the substation switching scheme.

Future system growth based on long-range forecasts may indicate the necessity for an economical, basic

arrangement initially with possible future conversion to a more sophisticated scheme as the number of

circuits increases. Important circuits may require additional protection or redundant supply. Equipment

maintenance requirements may necessitate bypassing facilities to enable circuit operation during

maintenance periods. Since the equipment that can be out of service for maintenance or during faults

without sacrificing system operation depends on alternative supplies and duplication of circuits, the

flexibility of the switching scheme is often one of the most important selection criteria. Large substations

with many circuits handling great amounts of power need to have high degrees of both flexibility and

reliability to continue service without interruption during the most undesirable conditions. Since

flexibility and reliability are directly proportional to cost, the ultimate configuration has to be the result of

a compromise.

4.2.3 Substation Expansion

Frequently, after initial substation construction, requirements change, and plans for the ultimate

capabilities of the substation are altered. As a result, expansion of the substation facilities may deviate

from the anticipated initial plan. To accommodate unforeseen future system modifications, consider the

flexibility of the arrangement. Since a typical substation can be expected to continue in service

indefinitely, maintaining maximum flexibility throughout each stage of expansion will ensure the least

costly and most efficient use of the facilities during the service period.

To facilitate future expansion, arrange the initial design to accommodate all requirements of a current

long-range system forecast. The site should be as large as practical to allow for future development.

Large areas readily allow for changes in the basic substation configuration and switching scheme should
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future conditions so dictate. Leave at least one and preferably both ends of all major buses open for

future expansion. When a basic initial arrangement is planned, placement of equipment should take into

account future expansion of the substation into a more complex, reliable, and flexible configuration.

Frequently, additional switches, switch stands, and bus supports are installed initially to facilitate future

expansion.

4.2.4 Substation Profile

The profile of substation structures and equipment has become an increasingly important aspect to

consider in substation layout. In the past, large lattice and box-type structures supporting overhead strain

buses were commonly used. Most substations currently being designed and constructed use low-profile

structures and rigid buswork, particularly for low-voltage distribution substations or in areas with natural

environmental screening.

Low-profile construction generally uses lower structures with a minimum number of members for

support. Larger pieces of equipment, such as power transformers and power circuit breakers, have

become smaller over the years. Consequently, substations are considered less obtrusive overall. The

height limitations causing the use of low-profile construction sometimes result in arrangements of

increased area, particularly for the lower voltage levels. Generally, the advantages of easier equipment

operation and maintenance as a result of reduced equipment sizes and effective locations make up for the

expense of purchasing somewhat larger sites.

4.2.5 Underground Circuits

An effective method to improve substation appearance is to install circuits underground as they leave the

substation. Low-profile construction using lower structures with fewer support members lends itself to

the use of underground circuits. Installing underground circuits can similarly improve the appearance of

substations with larger structures by reducing the size of some of the large supporting structures or

eliminating them altogether.

4.2.6 Equipment Removal

Substation arrangements have to include adequate space for the installation and possible removal of large

pieces of equipment such as power transformers and power circuit breakers. Buses, particularly in lowprofile arrangements, even when at acceptable operating elevations, can block the removal of equipment.

Consequently, it is important to consider equipment removal routes during the structure layout. Often the

most desirable arrangement has the main buses at higher elevations than the buses and equipment in the

substation bays. In this way, the main buses will not block the removal of equipment located in the

substation interior.

Removable bus sections can also be provided to permit movement of large equipment. This, however,

requires bus de-energization during the procedure.

Bay spacing has to be carefully evaluated during layout to allow for removal of equipment. In multi-bay

configurations, it is common to limit the number of bays to two before increasing the bay center-to-center

spacing. This allows equipment to be removed from a bay to the side and provides additional space for

moving the equipment between a bay and an adjacent bay, as diagrammed in Figure 4-1.
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Figure 4-1: Substation Plan View Showing Space for Equipment Removal

4.3 DISTRIBUTION SUBSTATIONS

Distribution substations are usually characterized by voltages up to 230 kV on the primary side and

12.5Y/7.2 kV, 13.2Y/7.6 kV, 13.8Y/8.0 kV, 24.9Y/14.4 kV, or 34.5Y/19.9 kV on the secondary side.

In recent years, the trend has been toward increasing system voltages. It is becoming more common to

eliminate the intermediate transmission substations and directly reduce the transmission voltages to

primary distribution levels. The distribution substations discussed are generally limited to the traditional

type characterized by simple bus arrangements and minimal equipment. However, the arrangements can

be expanded for use in larger distribution substations with higher voltages.

4.3.1 Basic Distribution Substation

Figure 4-2 is a one-line diagram for a basic distribution substation. Depending on the load being served,

it is possible that initial construction may be limited to one distribution circuit.

The subtransmission circuit enters the substation through a primary disconnect switch used principally to

isolate the substation from the subtransmission system for maintenance or when replacement of substation

equipment is required. It is usually of the three-pole, single-throw, group-operated type.
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Figure 4-2: Basic Distribution Substation

The power transformers commonly used in this application are two-winding type and may be single- or

three-phase units. In new substations and when replacing transformers or increasing transformer

capacity, the trend has been toward using three-phase transformers. In configurations using single-phase

transformers, a fourth transformer may be added as a spare. Use of three-phase transformers results in a

neater and less cluttered arrangement. However, since failure of a three-phase transformer means loss of

the substation, the overall design layout should provide facilities for the rapid installation of a mobile

transformer or a mobile substation.

The two primary distribution feeders of the substation illustrated in Figure 4-2 are protected by either

power circuit breakers or automatic circuit reclosers. Disconnect switches on both the source and load

sides permit isolation during maintenance or other periods when complete de-energization is required.

The switches can be either single-pole, single-throw, hook stick-operated or three-pole, single-throw,

group-operated, depending on the arrangement.

4.3.2 Transformer Primary Protective Devices

To prevent equipment damage from transformer or low-voltage bus faults, protective devices are

generally provided on the primary side of the transformer. These devices may also serve as primary

disconnects to enable isolation from the transmission system.

Several types of devices are available, including power fuses, circuit breakers, circuit switchers, and

vacuum interrupters. Selection of the type of device is based on the voltage, short-circuit conditions, and

transformer capacity.

4.3.3 Voltage Regulation

To maintain voltage at a uniform level, voltage regulation equipment is usually required in rural

distribution substations. The voltage can be regulated by using either feeder or bus regulation. Feeder

regulation may be used in multi-circuit distribution substations, where the circuits are very diverse in load

characteristics. With feeder regulation, the voltage of each distribution circuit can be individually

maintained to conform to the load characteristics. Bus regulation may be used in rural distribution

substations where the distribution feeders have similar load characteristics. Bus voltage may be

controlled by using power transformers with load tap changing mechanisms, single- or three-phase

voltage regulators, or switched capacitor banks.
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To permit voltage regulator maintenance without feeder or bus de-energization, bypass facilities are

provided as illustrated in Figure 4-3.

Figure 4-3: Voltage Regulator Bypass Arrangements

The switches normally used for regulator bypassing automatically combine all switching operations and

perform them in the correct operating sequence. Each combined switch can usually be installed in the

same space as one single-pole disconnect switch.

For a detailed discussion concerning the application of voltage regulators, see RUS Bulletin 1724D-114,

“Voltage Regulator Application on Rural Distribution Systems.”

4.3.4 Circuit Breaker/Recloser Bypass Facilities

Bypass facilities permit circuit breaker or recloser maintenance or repair without circuit de-energization.

Figure 4-4 illustrates a typical bypass arrangement.

The bypass switches usually consist of three independently operated hook stick switches, but a three-pole

group-operated switch can also be used. In some applications, it may be desirable to combine some of the

switches to facilitate installation. Figure 4-5 illustrates one possible configuration.

In this configuration, a tandem switch is used to combine the bypass switch and the load side disconnect

switch onto a single switch base. The combined switch can be installed in nearly the same space as one

single-pole disconnect switch.

To provide circuit protection during bypassing, the bypass switch can be replaced by a fuse.
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Figure 4-4: Typical Circuit Breaker/Recloser Bypass Arrangement

Figure 4-5: Use of Tandem Switches for Circuit Breaker/Recloser Bypassing

4.3.5 Surge Arresters

Transformers, regulators, and other substation equipment are particularly sensitive to transient

overvoltages. For the highest degree of equipment protection, surge arresters should be installed as close

as practical to the equipment being protected. In most instances, power transformers can be furnished

with surge arrester mounting brackets to facilitate installation. Separate arrester stands can also be used,

or the arresters can be installed on adjacent switching structures. For voltage regulator applications, the

surge arresters are normally installed directly on the regulator tanks.

When power transformers are protected by fuses, it is recommended that transformer surge arresters be

connected on the line side of the fuses, as close as practical to the power transformers. This will

minimize the stress on the fuse and help avoid partial melting of the fuse link when the surge arrester

responds to a transient overvoltage.

4.3.6 Enclosed Equipment

In certain applications, particularly when space is at a premium, consider use of switchgear, unit

substations, or partially enclosed equipment. Switchgear is a name commonly used in referring to

groupings of switching equipment contained in metal enclosures. All circuit breakers, metering and

control equipment, and interconnecting buswork are contained inside the enclosures.
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A unit substation consists of switchgear electrically and mechanically connected to at least one power

transformer. Various arrangements of power transformers and switchgear equipment are available to suit

individual requirements.

Use of switchgear, unit substations, and other types of enclosed equipment eliminates the need for

extensive field construction since most of the equipment is preassembled by the manufacturer or supplier.

Depending on the configuration, the equipment may be shipped completely assembled or in sections to be

connected together at the job site. Feeders are normally installed underground from the switchgear

compartments.

Partial enclosure of some of the low-voltage distribution equipment can be implemented to improve the

appearance of the substation. The equipment can be furnished in modular form to facilitate installation.

Interconnections between modules are usually underground, although overhead bus duct is occasionally

used.

4.4 TRANSMISSION SUBSTATIONS

Transmission substations are usually characterized by primary and secondary voltages of 69 kV or higher.

Since one transmission substation may supply several distribution substations and large loads, reliability

of service and flexibility of operation are extremely important. Facilities normally allow equipment

maintenance without circuit interruption. Multiple bus arrangements and extensive use of circuit breakers

for switching provide added system flexibility.

4.4.1 Basic Transmission Substation

Figure 4-6 is a one-line diagram for a basic transmission substation. Depending on system requirements,

initial substation construction may be limited to one power transformer and one subtransmission circuit.

Figure 4-6: Basic Transmission Substation

Power circuit breakers are included in the two transmission circuits to help prevent complete substation

shutdown for line faults. The circuit breakers have disconnect switches on both source and load sides to

permit isolation during maintenance or other periods requiring complete de-energization. These switches

are normally of the three-pole, single-throw, group-operated type, mounted on separate stands.

The power transformers commonly used are three-phase autotransformers, usually with tertiary windings.

Three-phase two-winding transformers are used when phase relationships have to be sustained between

the primary and the secondary systems. The disconnect switches on the low-voltage sides of the power
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transformers allow de-energization of one transformer while maintaining service to both low-voltage

circuits from the other transformer.

The low-voltage or secondary section of the substation illustrated in Figure 4-6 consists of two

subtransmission feeders protected by power circuit breakers. Disconnect switches on both the source and

load sides permit isolation during maintenance or other periods when complete de-energization is

required. The switches are normally of the three-pole, single-throw, group-operated type, but can be of

the single-pole, single-throw, and hook stick-operated type, depending on the voltage and arrangement.

Hook stick-operated switches usually are not considered above 69 kV.

4.4.2 Circuit Breaker Bypass Facilities

Bypass facilities can be provided for the power circuit breakers to permit maintenance without circuit deenergization. Figure 4-7 illustrates a typical arrangement.

Figure 4-7: Typical Circuit Breaker Bypass Arrangement

The bypass facilities normally consist of three independent three-pole, single-throw, group-operated

switches. The circuit breaker disconnect switches may be of the single-pole, single-throw, hook stickoperated type, depending on system voltage and bus configuration.

In most cases bypassing circuit breakers removes normal relay protection since the circuit breaker current

transformers are also removed from service. The overall protection scheme, have to be designed to

provide for this situation. Fused bypass switches may be used for temporary feeder protection.

4.4.3 Surge Arresters

Because of the desire for high reliability and the high cost of equipment replacement, surge arresters are

installed in various positions in transmission substations. Since power transformers are particularly

sensitive to overvoltages, they normally have arresters on each phase of both the primary and secondary.

Also install arresters on each ungrounded phase of the tertiary winding when it is brought out to provide

service.

The highest degree of equipment protection occurs with the surge arresters located as close as possible to

the equipment to be protected. Power transformers can usually be furnished with arrester mounting

brackets adjacent to the transformer bushings.

Occasionally, surge arresters or other surge protective equipment are located at the line entrances and

exits. In these instances, it is best to locate the arresters or other protective equipment on the line side of

the substation equipment to be protected to limit the lightning and switching surges to acceptable levels as

they enter the substation. Locating the arresters on the line side of the circuit breakers will also protect

the gap in the breakers when in the open position.
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4.4.4 Carrier Equipment

Line traps, coupling capacitor voltage transformers, and associated accessories are used when relaying or

communications systems dictate use of carrier equipment for signal transmission to remote terminals.

Normally, the line traps and coupling capacitor voltage transformers are installed on separate stands

located near the circuit entrance positions in the substations. In some instances, the two pieces of

equipment may be mounted on a common structure or stand, depending on the arrangement. The

particular relaying and communications schemes being used on the circuit will dictate the number of

phases containing line traps and coupling capacitor voltage transformers.

4.4.5 Voltage Transformers

Voltage transformers are used in conjunction with the circuit and equipment protection, synchronization,

and metering schemes. They are normally mounted on individual or three-position stands. Depending on

the bus configuration and the relaying schemes, the voltage transformers may be positioned near the

circuit entrance positions or adjacent to the buses.

It is usually desirable to provide a method for disconnecting the voltage transformers. One possible

method is to install the primary connections to the appropriate buses by using disconnectable clamps. In

arrangements using voltage transformers at the circuit positions, they can be positioned to allow deenergization by opening the power circuit breaker and the line disconnect switches.

4.4.6 Current Transformers

Current transformers used in both relaying and metering schemes can usually be located inside major

equipment such as power circuit breakers and power transformers. These current transformers are

normally multi-ratio bushing type and therefore do not require special mounting provisions. In some

cases, separately mounted current transformers may be required, such as for revenue metering purposes.

They are usually installed on individual stands and located as required.

4.4.7 Grounding Switches

Manually operated grounding switches are frequently used to ground incoming circuits during

maintenance or other out-of-service periods. These switches can be separately mounted or, as is usually

the case, can be furnished as part of the circuit disconnect switches. The switches can then be interlocked

in such a way as to prevent both from being closed simultaneously.

High-speed grounding switches are sometimes used in power transformer protection schemes to initiate

tripping of remote circuit breakers during transformer faults. As with manually operated grounding

switches, high-speed grounding switches can be separately mounted or can be furnished as part of groupoperated disconnect switches. High-speed grounding switches are normally installed on one phase only.

The use of high-speed grounding switches, while still in practice, is generally not preferred since its use

subjects the system to more of a shock and potentially affects more customers on the system.

4.5 SWITCHING STATIONS

Switching stations do not change system voltage from one level to another and therefore do not contain

power transformers. Switching stations usually operate at subtransmission or transmission voltage levels.
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Depending on system voltage, the equipment types and characteristics used in switching stations are

identical to those used in transmission stations.

4.5.1 Basic Switching Substation

Figure 4-8 is a one-line diagram for a basic switching substation with three terminals.

Figure 4-8: Basic Switching Substation

Power circuit breakers in the three circuits help prevent complete substation shutdown for line faults. The

circuit breakers have disconnect switches on both source and load sides to permit isolation during

maintenance or other periods requiring complete de-energization. Depending on station voltage and bus

configuration, the switches may be of the three-pole, single-throw, group-operated type or of the singlepole, single-throw, hook stick-operated type. Hook stick-operated switches usually are not considered

above 69 kV.

Bypass facilities can be provided to allow circuit breaker maintenance without de-energizing the circuit.

See Section 4.4.2 of this chapter for more information concerning circuit breaker bypass facilities.

4.5.2 Surge Arresters

Surge arresters or other surge protection equipment may be installed either on the line positions or on the

substation buses to protect against excessive lightning or switching surges.

A comparison of the costs of the surge protection equipment to the frequency and extent of possible

equipment damage can be evaluated to determine the desirability of the protective equipment. Possible

circuit or substation outages and equipment damage as a result of the unprotected surges should be

considered. In general, if there is any question, surge arresters should be installed for equipment and

circuit protection.

4.6 TYPICAL BUS CONFIGURATIONS

The typical bus configurations may be used for distribution, transmission, or switching substations at

voltages up to 345 kV. Details will vary depending on the type and voltage(s) of the substations. The

physical size, type, and arrangement of major equipment, such as power transformers, power circuit

breakers, and switches, may cause variance in the layouts to suit individual requirements. Portions of

different layouts may be combined, as required, to achieve desired configurations.

It is important that the engineer’s plans remain as flexible as possible during substation layout to allow for

unforeseen difficulties as designs progress. Coordinate activities with the equipment manufacturers to

ensure that each design detail reflects the actual equipment to be used.
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4.6.1 Single Bus

A single bus configuration consists of one main bus that is energized at all times and to which all circuits

are connected. This arrangement is the simplest, but provides the least amount of system reliability. Bus

faults or failure of circuit breakers to operate under fault conditions results in complete loss of the

substation. The single bus configuration can be constructed by using either low- or high-profile

structures. Figure 4-9 illustrates the single bus arrangement with low-profile structures and presents a

neat, orderly plan. The high-profile design, shown in Figure 4-10, accomplishes the same purpose and

may not require as large a site for a given system voltage.

The single bus arrangement is not recommended without circuit breaker bypass facilities that permit

circuit breaker maintenance while maintaining circuit operation. The high-profile configuration can

easily be modified to provide this feature by installing group-operated switches and the associated

buswork and connections in the positions shown in Figure 4-10. This arrangement, however, results in

loss of overcurrent protection for the circuit except by remote circuit breakers during the bypassing

operations. A fault occurring on the line with the breaker bypassed would result in complete substation

shutdown. The low-profile arrangement does not allow for future addition of this type of bypassing

equipment. Consequently, in both low-profile and some high-profile substations, the bypass facilities can

be installed outside the substation. Switches can be provided that, when closed, parallel two lines to

enable one circuit breaker to be removed from service. The other breaker then protects both circuits. If

this bypassing method is used, the equipment associated with both circuits, have to be capable of carrying

the total load of both circuits. If the load is greater than the equipment capability, the load should be

reduced. This method of circuit breaker bypassing may be more desirable in high-profile arrangements

than that shown in Figure 4-10 for lines where frequent or lengthy equipment maintenance is expected.

The high-profile configuration shown in Figure 4-10 is generally limited to distribution and

subtransmission voltage levels. At transmission voltage levels, independent structures and strain bus

interconnections are usually used.

4.6.1.1 Advantages:

1. Lowest cost

2. Small land area required

3. Easily expandable

4. Simple in concept and operation

5. Relatively simple for the application of protective relaying

4.6.1.2 Disadvantages:

1. High-profile arrangement equipped with circuit breaker bypass facilities does not provide for

circuit protection when bypass facilities are being used inside the substation.

2. A single bus arrangement has the lowest reliability.

3. Failure of a circuit breaker or a bus fault causes loss of the entire substation.

4. Maintenance switching can complicate and disable some of the protective relay scheme and

overall relay coordination.

5. Maintenance at the upper elevations of high-profile arrangements necessitates de-energization

or protection of the lower equipment.
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Figure 4-9: Single Bus—Low Profile
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Figure 4-10: Single Bus—High Profile
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4.6.2 Sectionalized Bus

An extension of the single bus configuration is the sectionalized bus arrangement shown in Figure 4-11.

This arrangement is basically two or more single bus schemes, each tied together with bus sectionalizing

breakers. The sectionalizing breakers may be operated normally open or closed, depending on system

requirements. In this arrangement, a bus fault or breaker failure causes only the affected bus section to be

removed from service and thus eliminates total substation shutdown. Usually, the fault can be isolated

and nonfaulted portions of the system restored to service easier and faster because of the increased

flexibility of this arrangement.

Figure 4-11: Sectionalized Bus

Physically, the equipment can be organized similar to that shown in Figures 4-9 and 4-10 for the single

bus arrangement. The sectionalizing breakers and their associated isolation switches are located in line

with the main bus. In the high-profile configuration, it is usually desirable to provide a separate bay for

the sectionalizing breakers and switches to facilitate maintenance and removal.

The arrangement of lines and transformers in a sectionalized bus arrangement depends on system

operating criteria. They should be arranged so as to prevent outage of lines or other circuits dependent on

each other. This can be accomplished by positioning the interrelated circuits on different bus sections to

eliminate concurrent shutdown. Perform a thorough analysis of all possible operational contingencies

identifying any undesirable conditions preceding the final determination of circuit grouping.

Bypassing arrangements for the sectionalized bus configuration can be provided as explained for the

single bus scheme.

4.6.2.1 Advantages:

1. Flexible operation

2. Higher reliability than single bus scheme

3. Isolation of bus sections for maintenance

4. Loss of only part of the substation for a breaker failure or a bus fault
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4.6.2.2 Disadvantages:

1. A sectionalized bus arrangement has a higher cost than a single bus scheme.

2. Additional circuit breakers are required for sectionalizing.

3. Sectionalizing may cause interruption of nonfaulted circuits.

4.6.3 Main and Transfer Bus

A main and transfer bus configuration consists of two independent buses, one of which, the main bus, is

normally energized. Under normal operating conditions, all incoming and outgoing circuits are fed from

the main bus through their associated circuit breakers and switches. If it becomes necessary to remove a

circuit breaker from service for maintenance or repairs, the integrity of circuit operation can be

maintained through use of the bypass and bus tie equipment. The bypass switch for the circuit breaker to

be isolated is closed, the bus tie breaker and its isolation switches are closed, and the bypassed breaker

and its isolation switches are opened to remove the breaker from service. The circuit is then protected by

the bus tie breaker.

Figure 4-12 illustrates a main and transfer bus configuration in a low-profile arrangement. For

comparison, Figure 4-13 shows the same switching scheme with high-profile box-type structures. With

the box-type structure arrangement, two circuit positions can be accommodated per equipment bay.

However, with the low-profile arrangement, each circuit requires its own bay and, as a result, somewhat

more land area may be required. When the low-profile configuration is used, equipment bays should be

limited in width to a maximum of two bays before the bay-to-bay centerline spacing is increased to

accommodate circuit breaker maintenance and removal. Without the additional space, these tasks can

become very difficult.

The high-profile, box-type structure arrangement shown in Figure 4-13 can accommodate multiple

circuits in a relatively small area. The configuration is particularly suitable in environmentally shielded

or otherwise isolated locations, where only a limited substation site is available. This arrangement is

generally limited to distribution and subtransmission voltage levels. At transmission voltage levels,

independent structures and strain bus interconnections can be used.

4.6.3.1 Advantages:

1. Accommodation of circuit breaker maintenance while maintaining service and line protection

2. Reasonable in cost

3. Fairly small land area

4. Easily expandable

4.6.3.2 Disadvantages:

1. An additional circuit breaker is required for bus tie.

2. Since the bus tie breaker, have to be able to be substituted for any line breaker, its associated

relaying may be somewhat complicated.

3. Failure of a circuit breaker or a bus fault causes loss of the entire substation.

4. Somewhat complicated switching is required to remove a circuit breaker from service for

maintenance.
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Figure 4-12: Main and Transfer Bus—Low Profile
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Figure 4-13: Main and Transfer Bus—High Profile
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4.6.4 Ring Bus

A ring bus configuration is an extension of the sectionalized bus arrangement and is accomplished by

interconnecting the two open ends of the buses through another sectionalizing breaker. This results in a

closed loop or ring with each bus section separated by a circuit breaker. For maximum reliability and

operational flexibility, each section should supply only one circuit.

In this arrangement, as with the sectionalized bus configuration, only limited bus sections and circuits are

removed from service because of line or bus faults or circuit breaker failure. For a line or bus fault, the

two circuit breakers on the sides of the affected bus section open to isolate the fault. The remaining

circuits operate without interruption. For a breaker failure, the two breakers on the sides of the affected

breaker open, along with a transfer trip to a remote breaker, to isolate the failed breaker and remove two

bus sections from service.

The ring bus arrangement provides for circuit breaker maintenance since any breaker can normally be

removed from service without interruption of service to any circuits. As a result, separate circuit breaker

bypass facilities are not required.

A number of equipment arrangements may be used to provide a ring bus configuration, depending on

anticipated substation expansion and possible system modifications. Figure 4-14 illustrates a typical ring

bus configuration. The arrangement shows four circuit positions, which is a practical maximum for a ring

bus configuration. Rather than expanding the ring bus to accommodate additional circuits, other more

flexible and reliable configurations, such as the breaker-and-a-half scheme, can be adopted. The ring bus

arrangement shown in Figure 4-14 is readily adaptable in the future to a breaker-and-a-half configuration

as shown in Figure 4-15. However, the relay and control panels have to be carefully planned to be

modified later for breaker-and-a-half operation.

Bay centerline spacing should be carefully planned to permit equipment maintenance and removal.

4.6.4.1 Advantages:

1. Flexible operation

2. High reliability

3. Isolation of bus sections and circuit breakers for maintenance without disrupting circuit

operation

4. Double feed to each circuit

5. No main buses

6. Expandable to breaker-and-a-half configuration

7. Economic design

4.6.4.2 Disadvantages:

1. Ring may be split by faults on two circuits or a fault during breaker maintenance to leave

possibly undesirable circuit combinations (supply/load) on the remaining bus sections. Some

consider this, however, to be a second contingency factor.

2. Each circuit has to have its own potential source for relaying.

3. This configuration is usually limited to four circuit positions, although larger rings are in

service, including 10-position ring buses. A 6-position ring bus is usually considered as a

maximum limit for the number of terminals in a ring bus.
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Figure 4-14: Ring Bus
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Figure 4-15: Breaker-and-a-Half
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4. This is a more involved relay scheme since each breaker has to respond to faults on two

circuits.

5. Automatic reclose schemes may be complex.

4.6.5 Breaker-and-a-Half

The breaker-and-a-half configuration consists of two main buses, each normally energized. Electrically

connected between the buses are three circuit breakers and, between each two breakers, a circuit as

diagrammed in Figure 4-15. In this arrangement, three circuit breakers are used for two independent

circuits; hence, each circuit shares the common center circuit breaker, so there are one-and-a-half circuit

breakers per circuit.

The breaker-and-a-half configuration provides for circuit breaker maintenance, since any breaker can be

removed from service without interrupting any circuits. Additionally, faults on either of the main buses

cause no circuit interruptions. Failure of a circuit breaker results in the loss of two circuits if a common

breaker fails and only one circuit if an outside breaker fails.

A typical bus configuration for a breaker-and-a-half arrangement is shown in Figure 4-15. This is the

same basic equipment assemblage as described for the ring bus scheme.

Frequently, substations are initially constructed with a ring bus arrangement and ultimately expanded into

a breaker-and-a-half configuration to obtain the additional flexibility and reliability required with the

additional circuits.

Bay centerline spacing should be carefully planned to permit equipment maintenance and removal.

4.6.5.1 Advantages:

1. Flexible operation

2. High reliability

3. Can isolate either main bus for maintenance without disrupting service

4. Can isolate any circuit breaker for maintenance without disrupting service

5. Double feed to each circuit

6. Bus fault does not interrupt service to any circuits

7. All switching done with circuit breakers

4.6.5.2 Disadvantages:

1. One-and-a-half breakers are required per circuit.

2. Relaying is involved, since the center breaker has to respond to faults of either of its associated

circuits.

3. Each circuit should have its own potential source for relaying.

4.6.6 Double Breaker–Double Bus

The double breaker–double bus configuration consists of two main buses, each normally energized.

Electrically connected between the buses are two circuit breakers and, between the breakers, one circuit,

as diagrammed in Figure 4-16. Two circuit breakers are required for each circuit.
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Figure 4-16: Double Breaker-Double Bus
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In the double breaker–double bus configuration, any circuit breaker can be removed from service without

interruption of any circuits. Faults on either of the main buses cause no circuit interruptions. Circuit

breaker failure results in the loss of only one circuit.

A typical bus configuration for a double breaker–double bus arrangement is shown in Figure 4-16.

Use of the double breaker–double bus configuration is usually limited to large generating stations because

of the high cost. The additional reliability afforded by this arrangement over the breaker-and-a-half

scheme usually cannot be justified for conventional transmission or distribution substations.

Occasionally, at a generating station, one bay of a breaker-and-a-half arrangement is used as a double

breaker–double bus arrangement for a generator terminal to provide equal access to either main bus.

4.6.6.1 Advantages:

1. Flexible operation

2. Very high reliability

3. Isolation of either main bus for maintenance without disrupting service

4. Isolation of any circuit breaker for maintenance without disrupting service

5. Double feed to each circuit

6. No interruption of service to any circuits from bus fault

7. Loss of only one circuit for breaker failure

8. All switching with circuit breakers

4.6.6.2 Disadvantages:

1. This configuration carries a high cost.

2. Two circuit breakers are required for each circuit.

4.6.7 Relative Switching Scheme Costs

The selection of a station switching scheme is the result of the evaluation of many factors, including such

intangibles as personal preference and judgment. Whatever arrangement is finally selected should meet

all known or anticipated requirements, such as operating and maintenance criteria, future expansion, and

reliability.

To assist in the evaluation, Table 4-1 provides a reasonable measure for the basis of economic

comparison.

Table 4-1: Switching Scheme Cost Comparison

Approximate Relative

Switching Scheme Cost Comparison

Single Bus 100%

Sectionalized Bus 122%

Main and Transfer Bus 143%

Ring Bus 114%

Breaker-and-a-Half 158%

Double Breaker–Double Bus 214%

The comparison is based on four-circuit low-profile arrangements with power circuit breakers in all

circuits. Power transformer costs are not included. In schemes utilizing other protective devices or
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different circuit quantities, the relative costs may vary from those listed. Prepare detailed construction

estimates for all schemes under consideration.

4.7 PROTECTION OF SUBSTATION INSULATION

4.7.1 General

Substation electrical equipment is subject to abnormal conditions as a result of direct lightning strokes,

lightning surges, switching surges, and faults on the system. These abnormal conditions can cause

overvoltages that may result in equipment flashover or insulation failure. To prevent equipment damage

and/or system shutdown from overvoltages, protective devices are used to limit the overvoltages to

reasonable levels. Application of these devices is usually a compromise between the costs of the devices

and the degree of protection desired.

The protection provided for substations and substation equipment can be broken into two main parts:

1. Surge protection, employed to protect the equipment from damaging overvoltages caused by

lightning surges, switching surges, and system faults

2. Direct stroke protection, employed to protect the equipment from direct lightning strokes

4.7.2 Surge Protection

Surge arresters are used to protect equipment against overvoltages caused by incoming surges. The

arresters function by discharging surge current to the ground system and then interrupt the current to

prevent flow of normal power frequency follow current to ground. A detailed discussion concerning the

application and selection of surge arresters can be found in Section 5.8.

4.7.3 Direct Stroke Protection

4.7.3.1 Shielding: Since the effects of a direct lightning stroke to an unshielded substation can be

devastating, it is recommended that some form of direct stroke protection be provided. Direct stroke

protection normally consists of shielding the substation equipment by using lightning masts, overhead

shield wires, or a combination of these devices. The types and arrangements of protective schemes used

are based on the size and configuration of the substation equipment.

4.7.3.2 Overhead Shield Wires: Overhead shield wires are often used to provide direct stroke

protection. The shield wires can be supported by the circuit pull-off structures, if conveniently located, to

extend over the substation. Since these shield wires are located above substation buses and equipment,

breakage could result in outage of and/or damage to equipment. To minimize possible breakage, the

overhead shield wire systems are constructed from high-quality, high-strength materials such as have

been accepted by RUS (see RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS

Electrification Borrowers”). Shield wires should be limited to a maximum design tension of 8900

newtons (2000 pounds) per conductor under the appropriate loading conditions as defined in the National

Electrical Safety Code. This tension is based only on wire strength and has to be coordinated with

support structure design. Lower tensions may be required for certain applications, depending on the

capabilities of the support structures. Sag has to be considered to ensure adequate clearance from

energized equipment.
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A complete overhead shield wire system should include protection for overhead circuits entering or

leaving the substation. In areas not employing transmission line shielding, substation shield wire systems

should be extended at least 805 meters (one-half mile) away from the substation to limit the exposure of

the phase conductors to direct strokes near the substation. Strokes occurring on the circuits beyond the

shielding will usually be attenuated enough by the time they reach the substation to be discharged

successfully by the surge arresters without causing equipment damage. For adequate protection, the

circuit wire systems should be directly connected to the substation shield wire system.

4.7.3.3 Shielding Masts: Shielding masts can be used for nearly all types of substations to provide

protection against direct lightning strokes. They are particularly useful in large substations and those of

low-profile design. Shielding masts can be guyed or self-supporting steel poles or lattice-type towers and

are usually made of steel. Other materials, such as precast concrete or aluminum, can also be used.

In some instances, shielding masts can also be used to provide support for substation lighting equipment.

4.7.3.4 Protection Calculation Methods: There are two widely used methods for designing

substation lightning protection:

1. Fixed angle

2. Rolling sphere

The zone of protection of a shielding system is the volume of space inside which equipment is considered

adequately protected by the system. A shielding system allowing no more that 0.1 percent of the total

predicted number of lightning strokes to terminate on the protected equipment is considered adequate for

most situations.

4.7.3.4.1 Fixed Angle Method: The fixed angle design method uses vertical angles to determine the

number, position, and height of shielding masts and wires. The shaded areas in Figure 4-17 illustrate the

zones of protection afforded by single- and double-mast or shield wire systems. For a single mast, the

zone of protection consists of a cone. For a single shield wire, the zone of protection is a wedge. When

two or more masts or shield wires are used, the zones of protection of each overlap to provide complete

coverage. Figure 4-17 also lists the ranges of angles that have been used for various shielding systems.

Figure 4-17: Zones of Protection for Masts and Shield Wires Using Fixed Angle Method
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4.7.3.4.2 Rolling Sphere Method: The rolling sphere method involves rolling an imaginary sphere of

a prescribed radius over the substation. The sphere rolls up and over (and is supported by) lightning

masts, shield wires, and other grounded metal objects intended for lightning shielding. A piece of

equipment is protected from a direct stroke if it remains below the curved surface of the sphere by virtue

of the sphere’s being elevated by shield wires or other devices. Equipment that touches the sphere or

penetrates its surface is not protected. The basic concept is shown in Figure 4-18.

Figure 4-18: Principle of Rolling Sphere. Ref. IEEE Std. 998-1996, Fig. 7-3.

Copyright © 1996. IEEE. All rights reserved.

The radius of the sphere is determined by calculating the strike distance. The strike distance is the length

of the final jump of the stepped leader as its potential exceeds the breakdown resistance of the last gap of

air to ground. A stepped leader is the static discharge that propagates from a cloud into the air.

The allowable stroke current that may be received by a substation bus without exceeding the withstand

value, or BIL, of the substation is defined by Equation 4-1:
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Equation 4-1

s

s

Z

2.2 *BIL

I =

Where:

Is = Allowable stroke current in kiloamperes

BIL = Basic lightning impulse level in kilovolts

Zs = Surge impedance of the conductor through which the surge is passing in ohms

Ref. IEEE Std. 998, Para. 5.2.2, Eq. 5-2A, and Definitions. Copyright © 1996. IEEE. All rights reserved.

The striking distance, indicated in Figure 4-18 by “R,” may be calculated using Equation 4-2 or 4-3:

Equation 4-2

0.65

m s R = 8KI

or

Equation 4-3

0.65

f s R = 26.25KI

Where:

Rm = Strike distance in meters

Rf = Strike distance in feet

Is = Return strike in kiloamperes

K = A coefficient to account for different striking distances to a mast, shield wire, or the

ground plane. K = 1 for strokes to wires or the ground plane, and K = 1.2 for strokes

to a lightning mast.

Ref. IEEE Std. 998, Para. 5.2.1, Eq. 5-1A, Eq. 5-1B, and Definitions. Copyright © 1996. IEEE. All

rights reserved.

These equations provide a very basic evaluation of the lightning protection provided by the rolling sphere

method. The many nuances and criteria on which the procedure is based are found in IEEE Std. 998,

“Guide for Direct Lightning Stroke Shielding of Substations.”

The engineer designing the shielding system needs to also take into account the isokeraunic level of the

area where the substation will be built. The isokeraunic level is the average annual number of

thunderstorm days for a given locality. The U.S. Weather Bureau publishes a chart that shows the

isokeraunic levels across the United States.

For a complete description of both the fixed angle and the rolling sphere methods, refer to IEEE Std. 998,

“Guide for Direct Lightning Stroke Shielding of Substations.”

4.7.3.5 Shielding System Grounding: A shielding system cannot effectively protect substation

equipment unless adequately grounded. Multiple low impedance connections from the shielding system

to the substation ground grid are essential. It is beneficial to use at least two separate connections to

ensure continuity and reliability. Whenever nonconducting masts or supports are used, install separate

ground cables to establish a direct connection from the shield system to the substation ground system.
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4.8 SUBSTATION INSULATORS

4.8.1 Outdoor Apparatus Insulators

4.8.1.1 Types: Outdoor apparatus insulators are used primarily to support rigid buswork and other

electrical equipment operated above ground potential. Apparatus insulators are normally manufactured

from electrical-grade wet-process porcelain and are available in two major types: cap and pin-type and

post-type. Other types are also available from some insulator manufacturers.

4.8.1.2 BIL (Impulse Withstand) Ratings of Outdoor Apparatus Insulators: For apparatus

insulators, impulse withstand voltages are commonly referred to as BILs. Apparatus insulators are

available with BIL ratings as shown in Table 4-2. Use of the BILs for the nominal system voltages listed

will normally ensure adequate coordination with protective devices and insulation systems of other

equipment for most operating conditions. In areas of extremely high contamination, it may be desirable

to increase the insulator BIL to levels higher than listed.

Table 4-2: Apparatus Insulator BIL Ratings for Nominal System Voltages.

Ref. NEMA SG-6-1995, Table 32-1. Reproduced with permission of the

National Electrical Manufacturers Association.

Nominal System Voltage

kV

Apparatus Insulator BIL

(Impulse Withstand)

kV

7.5 95

14.4 110

23 150

34.5 200

46 250

69 350

115 550

138 650

161 750

230 900

230 1050

345 1050

345 1300

According to ANSI Std. C37.30, “Definitions and Requirements for High-Voltage Air Switches,

Insulators, and Bus Supports,” equipment that depends on air for its insulating medium will have a lower

dielectric strength when operated at higher altitudes than when operating at lower altitudes. For altitudes

above 1000 meters (3300 feet), the correction factors shown in Table 4-3 should be applied to reduce the

insulator BILs.

4.8.1.3 Cap and Pin-Type Outdoor Apparatus Insulators: Cap and pin-type (Cpt) apparatus

insulators are the original insulator type used in substation construction. While Cpt is still in use, posttype insulators are more commonly used today in substation design and are recommended for any new

construction or rebuilding of existing facilities.

4.8.1.4 Post-Type Outdoor Apparatus Insulators: Post-type apparatus insulators are the type most

often used today for new substation construction. The uniform profile and smaller diameter enhance

insulator appearance. Post insulator types in general use are made of porcelain and polymer. The

polymer type is less rigid than porcelain or composite and is not recommended for switch supports.
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Table 4-3: Altitude Correction Factors/BIL. Ref. ANSI/IEEE Std.

C37.30-1992, Table 1. Copyright © 1992. IEEE. All rights reserved.

Altitude

Meters (feet)

Correction Factors to

Be Applied to BIL

1000 (3300) 1.00

1200 (4000) 0.98

1500 (5000) 0.95

1800 (6000) 0.92

2100 (7000) 0.89

2400 (8000) 0.86

2700 (9000) 0.83

3000 (10,000) 0.80

3600 (12,000) 0.75

4200 (14,000) 0.70

4800 (16,000) 0.65

5400 (18,000) 0.61

6000 (20,000) 0.56

Note: Correction factors are currently being reviewed.

Porcelain insulators are generally manufactured from one piece of electrical-grade wet-process porcelain

formed with a number of vertical skirts to achieve the required electrical characteristics. End caps for

mounting the insulators are cemented to the porcelain. The insulators are manufactured with a minimum

number of joints, which inherently reduces deflections.

The short skirts of post insulators make them less susceptible to damage from flashovers. Even if some of

the skirts are damaged, insulation integrity is usually maintained since the dry arcing distances are not

greatly affected.

Post-type insulators are available in two types: stacking and nonstacking. Single nonstacking insulators

are normally used through nominal voltages of 69 kV (350 kV BIL). At nominal voltages of 115 kV (550

kV BIL) and above, stacking insulators are used. See Figure 4-19.

Since post-type insulators are available in different colors, preferences should be made known in advance

of purchasing.

Post-type apparatus insulators are manufactured and tested in accordance with the following standards:

• ANSI C29.1 “Test Methods for Electrical Power Insulators”

• ANSI C29.9 “American National Standard for Wet-Process Porcelain Insulators (Apparatus,

Post Type)”

4.8.1.5 Leakage Distance of Outdoor Apparatus Insulators: Post-type apparatus insulators depend

on the insulating material contours to achieve the required leakage distances. Skirt breakage on a post

type usually will not cause insulator flashover since a much smaller percentage of the total leakage

distance is destroyed compared to the cap and pin type. Post-type apparatus insulators generally have

longer leakage distances than their counterparts, particularly at the lower BILs.

In areas of high contamination it is usually desirable to utilize insulators with either longer than standard
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Figure 4-19: Station Post Insulator. Courtesy of Lapp Insulator Co.

leakage distances or higher BILs to prevent electrical breakdown from surface contamination.

Application of insulators in unusual situations such as high contamination can sometimes best be

accomplished by referring the problem to the insulator manufacturers for recommendations.

4.8.1.6 Mechanical Strength of Outdoor Apparatus Insulators: Most apparatus insulators are

available in several mechanical strength ratings, based primarily on the cantilever strength of the

insulators. The various ratings available can be found in ANSI and NEMA standards and in

manufacturers’ literature.

For most applications, cantilever strength is the most important mechanical characteristic. However,

depending on the actual insulator application, some of the other characteristics can become important and

should be considered. These insulator characteristics include tensile strength, compressive strength, and

torsional strength. The design and manufacture of post-type apparatus insulators allow equal cantilever

strength ratings in both upright and underhung mounting positions.

Typical characteristics of cap and pin-type and post-type apparatus insulators can be found in Tables 4-4

and 4-5, respectively. Post insulators are recommended.
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Table 4-4: Typical Characteristics of Cap and Pin-Type Insulators. Ref. Std. ANSI C29.8-1985, Table 1.

Reproduced with permission of the National Electrical Manufacturers Association.

BIL (IMPULSE TECHNICAL UPRIGHT CANTILEVER UNDERHUNG CANTILEVER BOLT

WITHSTAND) REFERENCE STRENGTH STRENGTH CIRCLE HEIGHT LEAKAGE DISTANCE

kV NUMBER POUNDS (NEWTONS) POUNDS (NEWTONS) IN. (CM) IN. (CM) IN. (CM)

 95 1 2,000 (8,896) 1,000 (4,448) 3 (7.62) 7.5 (19.1) 7.5 (19.1)

 95 41 4,000 (17,792) 3,000 (13,344) 3 (7.62) 8 (20.3) 8 (20.3)

 110 4 2,000 (8,896) 1,000 (4,448) 3 (7.62) 10 (25.4) 12.0 (30.5)

 110 44 4,000 (17,792) 3,000 (13,344) 5 (12.7) 10 (25.4) 14.0 (35.6)

 150 7 2,000 (8,896) 1,000 (4,448) 3 (7.62) 12 (30.5) 20.0 (50.8)

 150 46 4,000 (17,792) 3,000 (13,344) 5 (12.7) 12 (30.5) 18.0 (45.7)

 190 147 3,000 (13,344) 2,000 (8,896) 3 (7.62) 14.5 (36.8) 26.0 (66.0)

 200 10 2,000 (8,896) 1,000 (4,448) 3 (7.62) 15 (38.1) 28.0 (71.1)

 200 49 4,000 (17,792) 3,000 (13,344) 5 (12.7) 15 (38.1) 28.0 (71.1)

 210 140 7,000 (31,136) 4,000 (17,792) 5 (12.7) 14.5 (36.8) 33.0 (83.8)

 210 141 10,000 (44,480) 6,000 (26,688) 5 (12.7) 14.5 (36.8) 33.0 (83.8)

 210 142 10,000 (44,480) 6,000 (26,688) 7 (17.8) 14.5 (36.8) 33.0 (83.8)

 210 191 20,000 (88,960) 12,000 (53,376) 7 (17.8) 14.5 (36.8) 33.0 (83.8)

 210 164 4,000 (17,792) 3,500 (15,568) 3 (7.62) 14.5 (36.8) 33.0 (83.8)

 250 13 2,000 (8,896) 1,000 (4,448) 3 (7.62) 18 (45.7) 36.0 (91.4)

 250 165 3,000 (13,344) 2,000 (8,896) 3 (7.62) 18 (45.7) 36.0 (91.4)

 350 16 1,500 (6,672) 1,000 (4,448) 3 (7.62) 29 (73.7) 52.0 (132.0)

 350 56 3,000 (13,344) 2,350 (10,453) 5 (12.7) 29.0 (1) (73.7) 66.0 (168.0)

 350 166 2,000 (8,896) 2,000 (8,896) 3 (7.62) 29.0 (1) (73.7) 66.0 (168.0)

 550 19 1,700 (7,562) 1,470 (6,539) 5 (12.7) 43.5 (1) (111.0) 99.0 (252.0)

 550 167 1,000 (4,448) 1,000 (4,448) 3 (7.62) 43.5 (1) (111.0) 99.0 (252.0)

 650 170 1,000 (4,448) 1,000 (4,448) 3 (7.62) 54.0 (1) (137.2) 108.0 (274.3)

 750 168 1,000 (4,448) 1,000 (4,448) 3 (7.62) 58.0 (1) (147.3) 132.0 (335.3)

 750 25 1,200 (5,338) 1,070 (4,759) 5 (12.7) 58.0 (1) (147.0) 132.0 (335.0)

 750 123 2,000 (8,896) 1,750 (7,784) 5 (12.7) 58.0 (1) (147.0) 132.0 (335.0)

 900 126 910 (4,048) 840 (3,736) 5 (12.7) 72.5 (1) (184.0) 165.0 (419.0)

 900 27 1,450 (6,450) 1,350 (6,005) 5 (12.7) 72.5 (1) (184.0) 165.0 (419.0)

1050 128 750 (3,336) 700 (3,114) 5 (12.7) 87.0 (1) (221.0) 198.0 (503.0)

1050 28 1,170 (5,204) 1,100 (4,893) 5 (12.7) 87.0 (1) (221.0) 198.0 (503.0)

1050 196 2,300 (10,230) 2,300 (10,230) 7 (17.8) 87 (1) (221.0) 198 (503.0)

1300 133 1,000 (4,448) 950 (4,226) 7 (17.8) 101.5 (1) (257.8) 231 (586.7)

1300 197 2,000 (8,896) 2,000 (8,896) 7 (17.8) 101.5 (1) (257.8) 231 (586.7)

Notes:

(1) Does not include 3.5-inch (8.89 cm) high sub-base that is required for full BIL.

(2) The insulators listed are representative of those currently available. Additional ratings are available for some voltages. Refer to

manufacturers’ data for information.

(3) The characteristics listed are typical. Refer to manufacturers’ data for actual ratings and additional characteristics.
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Table 4-5: Typical Characteristics of Post-Type Insulators. Ref. ANSI Std. C29.9-1983, Tables 1 and 2.

Reproduced with permission of the National Electrical Manufacturers Association.

BIL (IMPULSE TECHNICAL UPRIGHT

CANTILEVER

UNDERHUNG

CANTILEVER

BOLT CIRCLE

WITHSTAND) REFERENCE STRENGTH STRENGTH TOP BOTTOM HEIGHT LEAKAGE

DISTANCE

kV NUMBER POUNDS (NEWTONS) POUNDS (NEWTONS) IN. (CM) IN. (CM) IN. (CM) IN. (CM)

95 202 2000 (8896) 2000 (8896) 3 (7.62) 3 (7.62) 7.5 (19.1) 10.5 (26.7)

95 202 4000 (17792) 4000 (17792) 5 (12.7) 5 (12.7) 7.5 (19.1) 10.5 (26.7)

110 205 2000 (8896) 2000 (8896) 3 (7.62) 3 (7.62) 10 (25.4) 15.5 (39.4)

110 225 4000 (17792) 4000 (17792) 5 (12.7) 5 (12.7) 12 (30.5) 15.5 (39.4)

150 208 2000 (8896) 2000 (8896) 3 (7.62) 3 (7.62) 14 (35.6) 24 (61.0)

150 227 4000 (17792) 4000 (17792) 5 (12.7) 5 (12.7) 15 (38.1) 24 (61.0)

200 210 2000 (8896) 2000 (8896) 3 (7.62) 3 (7.62) 18 (45.7) 37 (94)

200 231 4000 (17792) 4000 (17792) 5 (12.7) 5 (12.7) 20 (50.8) 37 (94)

250 214 2000 (8896) 2000 (8896) 3 (7.62) 3 (7.62) 22 (55.9) 43 (109)

250 267 4000 (17792) 4000 (17792) 5 (12.7) 5 (12.7) 24 (61.0) 43 (109)

350 216 1500 (6672) 1500 (6672) 3 (7.62) 3 (7.62) 30 (76.2) 72 (183)

350 278 3000 (13344) 3000 (13344) 5 (12.7) 5 (12.7) 30 (76.2) 72 (183)

550 286 1700 (7562) 1700 (7562) 5 (12.7) 5 (12.7) 45 (114) 99 (251)

550 287 2600 (11564) 2600 (11564) 5 (12.7) 5 (12.7) 45 (114) 99 (251)

650 288 1400 (6227) 1400 (6227) 5 (12.7) 5 (12.7) 54 (137) 116 (295)

650 289 2200 (9786) 2200 (9786) 5 (12.7) 5 (12.7) 54 (137) 116 (295)

750 291 1200 (5338) 1200 (5338) 5 (12.7) 5 (12.7) 62 (157) 132 (335)

750 295 1850 (8229) 1850 (8229) 5 (12.7) 5 (12.7) 62 (157) 132 (335)

900 304 950 (4226) 950 (4226) 5 (12.7) 5 (12.7) 80 (203) 165 (419)

900 308 1450 (6450) 1450 (6450) 5 (12.7) 5 (12.7) 80 (203) 165 (419)

1050 312 800 (3558) 800 (3558) 5 (12.7) 5 (12.7) 92 (234) 198 (503)

1050 316 1250 (5560) 1250 (5560) 5 (12.7) 5 (12.7) 92 (234) 198 (503)

1050 362 2300 (10230) 2300 (10230) 7 (17.8) 7 (17.8) 92 (234) 198 (503)

1300 324 1000 (4448) 1000 (4448) 5 (12.7) 5 (12.7) 106 (269) 231 (587)

1300 367 1450 (6450) 1450 (6450) 5 (12.7) 7 (17.8) 106 (269) 231 (587)

1300 368 2000 (8896) 2000 (8896) 7 (17.8) 7 (17.8) 106 (269) 231 (587)

1300 369 2050 (9118) 2050 (9118) 5 (12.7) 7 (17.8) 106 (269) 231 (587)

Notes:

(1) The insulators listed are representative of those currently available. Additional ratings are available for some voltages. Refer to manufacturers’ data for

information.

(2) The characteristics listed are typical. Refer to manufacturers’ data for actual ratings and additional characteristics.
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4.8.1.7 Mounting Outdoor Apparatus Insulators: Most apparatus insulators are furnished with end

caps with four mounting holes arranged in either 7.62-centimeter (3-inch), 12.7-centimeter (5-inch), or

17.8-centimeter (7-inch) bolt circles, or 30.5-centimeter (12-inch) or 35.6-centimeter (14-inch) bolt

circles, depending on the insulator strength and voltage rating. The mounting holes are usually tapped for

bolts of 1/2" with 13 threads per inch, 5/8" with 11 threads per inch, or 3/4" with 10 threads per inch,

respectively. Adapters are available to go from one bolt circle size to another.

Upright or underhung mounting usually does not present major problems, provided the insulators are

utilized within their mechanical and electrical capabilities. When the insulators are installed horizontally,

the weight of the insulators, fittings, buses, and any other supported equipment have to be considered to

determine the permissible loads. Some manufacturers recommend reducing the allowable loads from the

tabulated values for horizontally mounted insulators. Unusual applications can be referred to the

manufacturers for recommendations.

4.8.2 Suspension Insulators

4.8.2.1 Types: Suspension insulators are used as insulation and support for strain buses in

substations. Suspension insulators are available in several forms to suit individual requirements.

Distribution deadend-type suspension insulators can be used at distribution voltages for substation strain

buses. Distribution deadend suspension insulators normally have clevis-type connections. Conventional

suspension insulators are normally used for strain bus insulation at higher voltages and can be furnished

with either clevis or ball and socket connections. The conventional suspension insulators most commonly

used are 25.4 centimeters (10 inches) in diameter and 14.6 centimeters (5 3⁄4 inches) in length. Suspension

insulators are manufactured out of porcelain, polymer, and glass. See Figure 4-20.

Suspension insulators acceptable for use on RUS-financed systems are listed in RUS IP 202-1.

4.8.2.2 Electrical Characteristics of Suspension Insulators. To achieve the necessary electrical

characteristics, a number of suspension insulators are strung together in series. It is important to

coordinate the insulation characteristics of suspension insulator strings with the insulation systems of

other substation equipment and the characteristics of various insulation protective devices.

The quantity of suspension insulators chosen for a particular application should be large enough to

prevent unnecessary flashovers. Overinsulation, however, can result in flashovers occurring from phase

to phase rather than from phase to ground. Consequently, the quantity of insulators should be small

enough that all flashovers occur to ground.

Table 4-6 lists the recommended minimum quantities of standard 14.6 x 25.4 cm (5 3⁄4 x 10 in.)

suspension insulators for particular nominal system voltages and BILs. Additional insulators should be

considered under the following conditions:

1. Above 1000 meters (3300 feet), the correction factors listed in Table 4-3 should be applied to

the BILs and the insulator quantities correspondingly increased.

2. In areas of high contamination, it may be necessary to increase the insulator quantities or

consider the use of specially designed equipment.

3. When deadending on steel structures, an additional insulator is typically added.

4. When installed at an angle other than vertical, one or two insulators should be added when the

angle from vertical approaches 45 degrees and 90 degrees, respectively.
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Figure 4-20: Suspension Insulator
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Table 4-6: Minimum Quantity of Suspension Insulators

Nominal System

Phase-to-Phase Voltage

kV

BIL

kV

Minimum Quantity of

Suspension Insulators*

7.5 95 1

14.4 110 2

23 150 2

34.5 200 3

46 250 4

69 350 5

115 550 8

138 650 9

161 750 10

230 900 12

230 1050 14

345 1300 20

*For standard 14.6- x 25.4-centimeter (5 3⁄4- x 10-inch) suspension insulators.

4.8.2.3 Mechanical Strength of Suspension Insulators: Suspension insulators are tested and

categorized with simultaneous mechanical-electrical strength ratings, as listed in RUS IP 202-1. These

strength ratings are not the actual loads the insulators are designed to operate under, but represent ultimate

strengths. The insulators also have proof test ratings specified in ANSI Std. C29.2 as one half the

mechanical–electrical ratings. These ratings are the actual loads that the insulators have withstood during

testing. The maximum suspension insulator loading should not exceed 40 percent of the mechanical–

electrical strength ratings listed in RUS IP 202-1.

4.9 ELECTRICAL CLEARANCES

Table 4-7 lists the electrical clearances for outdoor substation construction. The values identified as

minimums should be maintained or exceeded at all times. Phase-to-ground and phase-to-phase clearances

should be coordinated to ensure that possible flashovers occur from phase to ground rather than from

phase to phase.

Table 4-8 lists the phase spacing of various types of outdoor air switches. The minimum metal-to-metal

clearances should be maintained at all times with the switches in the open position, closed position, or

anywhere between the open and closed positions.
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Table 4-7: Outdoor Electrical Substation Clearances. Ref. ANSI C37.32-1996, Table 5; NEMA SG-6-1995, Table 32-1.

Reproduced with permission of the National Electrical Manufacturers Association.

Nominal

PhasetoPhase

Voltage

kV

Maximum

PhasetoPhase

Voltage

kV

BIL

kV

Minimum Metal - toMetal for Rigid

Conductors

meters (inches)

Centerline-toCenterline

Phase Spacing

for Rigid Buses

meters

(inches)

Minimum to

Grounded Parts

for Rigid

Conductors

meters (inches)

Minimum

Between Bare

Overhead

Conductors and

Ground for

Personal Safety

meters (feet) (3)

Minimum

Between Bare

Overhead

Conductors and

Roadways Inside

Substation

Enclosure

meters (feet) (4)

 7.5 8.3 95 0.178 (7) 0.457 (18) 0.152 (6) 2.44 (8) 6.10 (20)

 14.4 15.5 110 0.305 (12) 0.610 (24) 0.178 (7) 2.74 (9) 6.40 (21)

 23 25.8 150 0.381 (15) 0.762 (30) 0.254 (10) 3.05 (10) 6.71 (22)

 34.5 38 200 0.457 (18) 0.914 (36) 0.330 (13) 3.05 (10) 6.71 (22)

 46 48.3 250 0.533 (21) 1.22 (48) 0.432 (17) 3.05 (10) 6.71 (22)

 69 72.5 350 0.787 (31) 1.52 (60) 0.635 (25) 3.35 (11) 7.01 (23)

115 121 550 1.35 (53) 2.13 (84) 1.07 (42) 3.66 (12) 7.62 (25)

138 145 650 1.60 (63) 2.44 (96) 1.27 (50) 3.96 (13) 7.62 (25)

161 169 750 1.83 (72) 2.74 (108) 1.47 (58) 4.27 (14) 7.92 (26)

230 242 900 2.26 (89) 3.35 (132) 1.80 (71) 4.57 (15) 8.23 (27)

230 242 1050 2.67 (105) 3.96 (156) 2.11 (83) 4.88 (16) 8.53 (28)

345 362 1050 2.67 (105) 3.96 (156) 2.13 (84)* 4.88 (16) 8.53 (28)

345 362 1300 3.02 (119) 4.43 (174) 2.64 (104)* 5.49 (18) 9.14 (30)

Notes: (1) Values listed are for altitudes of 1000 meters (3300 feet) or less. For higher altitudes, the altitude correction factors listed in Table 4-3 should be

applied.

(2) This is the minimum clearance from the top of structure, equipment, or apparatus foundation to energized conductors.

(3) In no cases should the clearance from the top of a foundation to the bottom of equipment bushings or insulators of energized equipment or

apparatus be less than 2.44 meters (8 feet).

(4) This dimension indicates the clearance required for truck traffic under the overhead line while maintaining ground clearance.

* Ground clearance for voltages 362 kV and above is selected on the premise that, at this level, selection of the insulation depends on switching

surge levels of the system. The values were selected from Table 1 of IEEE Transaction Paper T-72-131-6 (Vol. 5, page 1924), which is a report of

the Transmission Substations Subcommittee. For additional switching surge values and ground clearances, refer to ANSI Std. C2.
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Table 4-8: Phase Spacing of Outdoor Air Switches. Ref. ANSI Std. C37.32-1996, Table 5.

Reproduced with permission of the National Electrical Manufacturers Association.

Centerline-to-Centerline Phase Spacing

meters (inches)

Nominal

Phase-toPhase Voltage

kV

Maximum

Phase-to-Phase

Voltage kV

BIL

kV

Minimum Metal-toMetal for Air Switches

meters (inches)

Vertical Break

Disconnect

Switches

Side or Horizontal

Break Disconnect

Switches

All Horn Gap

Switches

7.5 8.3 95 0.175 (7) 0.457 (18) 0.762 (30) 0.914 (36)

14.4 15.5 110 0.305 (12) 0.610 (24) 0.762 (30) 0.914 (36)

23 25.8 150 0.381 (15) 0.762 (30) 0.914 (36) 1.22 (48)

34.5 38 200 0.457 (18) 0.914 (36) 1.22 (48) 1.52 (60)

46 48.3 250 0.533 (21) 1.22 (48) 1.52 (60) 1.83 (72)

69 72.5 350 0.787 (31) 1.52 (60) 1.83 (72) 2.13 (84)

115 121 550 1.35 (53) 2.13 (84) 2.74 (108) 3.05 (120)

138 145 650 1.60 (63) 2.44 (96) 3.35 (132) 3.66 (144)

161 169 750 1.83 (72) 2.74 (108) 3.96 (156) 4.27 (168)

230 242 900 2.26 (89) 3.35 (132) 4.87 (192) 4.87 (192)

230 242 1050 2.67 (105) 3.96 (156) 5.50 (216) 5.50 (216)

345 362 1050 2.67 (105) 3.96 (156) 5.49 (216) 5.49 (216)

345 362 1300 3.02 (119) 4.43 (174) — — — —

Notes: (1) Values taken from ANSI C37.32 and NEMA SG6.

(2) Values listed are for altitudes of 1000 meters (3300 feet) or less. For higher altitudes, the altitude correction factors listed in Table

4-3 should be applied.
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When nonrigid conductors are used for outdoor overhead substation buses, the movement of the

conductors caused by temperature changes and wind and ice loads has to be considered. The usual

practice is to increase the centerline-to-centerline bus spacing and the phase-to-ground clearances to

compensate for these conditions. Increase the minimum metal-to-metal, bus centerline-to-centerline, and

minimum ground clearances listed in Table 4-7 by at least 50 percent for nonrigid conductors. Check to

ensure that the minimum metal-to-metal clearances listed in Tables 4-7 and 4-8 are maintained or

exceeded at all times for all expected temperature and loading conditions. The movement of nonrigid

conductors can also be calculated using the NESC conductor movement envelopes for line conductors.

In some locations, contamination from airborne particles necessitates increasing the minimum electrical

clearances. Satisfactory operation can usually be obtained by using clearances one step above those

normally used. In extremely contaminated locations, additional clearance may be required.

Since the dielectric strength of air-insulated equipment decreases with increasing altitude, the clearances

listed in Table 4-7 have to be modified for use at altitudes above 1000 meters (3300 feet). To determine

appropriate clearances for use above 1000 meters (3300 feet), first derate the standard BILs by applying

the factors listed in Table 4-3. Then choose the clearances from Table 4-7 corresponding to the derated

BILs selected. For example, at an altitude of 2400 meters (8000 feet), a maximum voltage of 121 kV is to

be used. From Table 4-3, the standard BIL of 550 kV has to be derated by applying a multiplying factor

of 0.86. Table 4-9 shows the effects of derating for 2400 meters (8000 feet):

Table 4-9: Effects of Derating

for 2400 Meters

Standard BILs

kV

Derated BILs

kV

550 473

650 559

750 645

A 650 kV BIL should be selected for use at 2400 meters (8000 feet) to provide a BIL equivalent to 550

kV at altitudes of 1000 meters (3300 feet) and below. The clearances to be used are those associated with

the 650 kV standard BIL, as listed in Tables 4-7 and 4-8.

As an option to the above equipment selection, the engineer may evaluate the derated BIL in terms of the

capability of surge arresters applied to the equipment to provide protection to the equipment. With

applicable protective margins, surge arresters available today may be able to protect voltage-derated

equipment without increasing the equipment BIL for compensation.

In addition to the electrical clearances previously described, it is necessary to provide adequate space for

equipment maintenance. In arrangements where equipment such as power circuit breakers, reclosers,

disconnect switches, power transformers, or other equipment has to be maintained while portions of

adjacent equipment remain energized, provide sufficient space around the equipment to prevent

accidental contact by maintenance personnel.

In arrangements with buses or equipment crossing over other buses and equipment, maintain adequate

clearance between the adjacent buses and equipment for all operational conditions. Position power

transformers and power circuit breakers to permit removal of any bushing. Locate switches and other

equipment with externally moving parts to prevent infringement on the minimum clearances listed in

Tables 4-7 and 4-8 during operation or when in any position. Also consider conductor, equipment, or

support structure movement during heavily loaded or deformed conditions.
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The clearances listed in Tables 4-7 and 4-8 are adequate for most situations and exceed the requirements

of the National Electrical Safety Code. The clearances listed in the NESC have to be maintained or

exceeded at all times.

Another clearance requirement is the location of the substation perimeter fence with respect to live parts

within the substation. A safety clearance zone is required to keep someone outside the substation from

sticking an object through the fence and coming in contact with live parts or getting close enough to cause

a flashover to occur. Use Figure 4-21 to locate exposed live parts outside the safety clearance zone.

4.10 BARE CONDUCTORS

4.10.1 Conductor Materials

Copper and aluminum are the two major conductor materials used for substation buses and equipment

connections. Both materials can be fabricated into various types of flexible or rigid conductors. The

trend in substation construction is toward use of mostly aluminum conductors. Copper conductors are

used principally for expansion of similar systems in existing substations.

The conductivity of aluminum is from 50 to 60 percent that of copper, depending on the aluminum alloy.

Consequently, larger aluminum conductors are required to carry the same currents as copper conductors.

The larger aluminum conductor diameters result in greater wind and ice loads but tend to minimize

corona, which is more of a problem at higher voltages.

For the same ampacity, copper conductors weigh approximately twice as much as aluminum conductors.

The higher copper conductor weights can result in more sag as compared with aluminum conductors for

equal spans. To reduce the sag, it is usually necessary to increase the number of supports for rigid

conductors or, in the case of flexible conductors, increase the tensions.

4.10.2 Rigid Conductors

Rigid electrical conductors are available in a variety of shapes and sizes to suit individual requirements.

Some of the more commonly used shapes include flat bars, structural shapes, and tubes. Specific physical

and electrical properties and application data can be obtained from the conductor manufacturers.

4.10.2.1 Flat Bars: Flat bars can be utilized for outdoor substation buses and are particularly suitable

since they can be easily bent and joined. For high-current applications, a number of flat bars can be

grouped together, leaving a small space between the bars to facilitate heat dissipation. The ampacity of a

group of flat bars depends on whether the bars are arranged vertically or horizontally. The number of

bars that can be grouped together is limited because of skin and proximity effects. Flat bars are usually

limited to use at lower voltages because of corona.

Because of their inherent lack of rigidity, supports for flat bar buses are usually closely spaced to

minimize the effects of meteorological loads and short-circuit forces.

4.10.2.2 Structural Shapes: The structural shape conductors that have been used in outdoor

substation construction consist primarily of angle and channel types. The flat surfaces permit bolting

directly to support insulators and provide convenient connection points. To increase ampacity, two angles

or channels can be used. Special fittings are usually required for these configurations. The positioning

and grouping of structural shapes have limitations similar to those of flat bars.
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Dimensions for use with Figure 4-21, Fence Safety Clearance

Nominal Voltage Dimension A Dimension B

Between Phases Ft M Ft M

151-34,500 15.0 4.6 10.0 3.1

46,000-69,000 16.0 4.9 12.0 3.7

115,000 16.7 5.1 13.0 4.0

138,000 17.1 5.2 14.0 4.3

161,000 17.6 5.4 14.0 4.3

230,000 19.0 5.8 16.0 4.9

345,000 21.3 6.5 18.0 5.5

500,000 24.9 7.6 21.0 6.4

765,000 29.7 9.1 23.0 7.0

NOTES:

1. Dimension A is equal to the vertical clearance of wires, conductors, and cables above spaces and ways subject

to pedestrians or restricted traffic only (ANSI C2-1987 [1], Rules 232A and 232B, and Table 232-1, 5) for the

voltage considered.

2. The B Dimension was established after considering the horizontal clearance of unguarded live parts in electric

supply stations (ANSI C2-1987 [1], Rule 124 A, and Table 124-1), plus the effective length of a rod or pole that

could be inserted through the electric supply station fence. The horizontal factors (ANSI C2-1987 [1], Table 124-

1, Part C).

3. The values shown for Dimension A for nominal voltages between phases of 115,000 and above should be

increased 3 percent for each 1000 ft (300 m) in excess of 3300 ft (1000 m) above mean sea level.

Figure 4-21: Safety Clearance to Electric Supply Station Fences.

Ref. IEEE Std. 119-1988, Fig. 1. Copyright © 1988. IEEE. All rights reserved.
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The rigidity of both angle and channel shapes is somewhat higher than for flat bars of the same ampacity.

Consequently, support spacing can usually be increased.

4.10.2.3 Tubular Shapes: Square and round tubular shapes are considerably more rigid than either

flat bars or structural shapes of the same ampacity and permit longer spans. The flat surfaces of square

tubes provide convenient connection and support points. To facilitate heat dissipation, ventilation holes

are sometimes provided in the square tubes. Round tubular conductors are the most popular shape used in

outdoor substation construction. The round shape is very efficient structurally and electrically and

minimizes corona at higher voltages. The special fittings required for connecting, terminating, and

supporting round tubular conductors are widely available.

4.10.2.4 Special Shapes: Special shapes combining the advantages of several of the standard shapes

are also available. Integral web channel buses, uniform thickness angles, and other special configurations

can be furnished.

4.10.2.5 Aluminum Alloys and Tempers: Aluminum conductors are available in a variety of alloys

and tempers with different conductor conductivities and strengths. Round tubular conductors are usually

specified as either 6061-T6 or 6063-T6 alloy. The 6063-T6 alloy has a conductivity approximately 23

percent higher and a minimum yield strength approximately 29 percent lower than the 6061-T6 alloy.

Consequently, the 6063-T6 alloy can carry higher currents but may require shorter support intervals.

Both Schedule 40 and 80 pipe are available in either alloy. The Schedule 80 sizes have wall thicknesses

approximately 40 percent thicker than the Schedule 40 sizes, resulting in lower deflections for equal span

lengths.

Alloy 6106-T61 is frequently utilized for flat bars, structural shapes, and square tubes. Other alloys and

tempers are available for special applications.

4.10.3 Flexible Conductors

Flexible electrical conductors can be used as substation buses and equipment taps. The conductors are

normally cables fabricated by stranding a number of small conductors into one larger conductor.

Stranding provides the required conductor flexibility while maintaining strength. The flexibility can be

increased by reducing the diameter and increasing the quantity of individual conductors. Bare electrical

cables for substation construction are usually concentric lay stranded with Class A or AA stranding in

accordance with ASTM Std. B231.

Most flexible conductors used in substation construction consist of all copper, all aluminum, or aluminum

with steel reinforcing (ACSR). The conductor type selected for a particular application is usually based

on the span length, tension and tolerable sag, and cost. For long spans, large supporting structures will be

required. The size and cost of these structures may depend on the conductor type and should be

considered during the selection process.

Flexible conductors are available in many sizes. Size selection is based on ampacity, strength, weight,

and diameter. Conductor diameter becomes increasingly important at higher voltages where corona can

be a problem.

Data concerning the physical and electrical properties of the various wire types can be found in

manufacturers’ literature.
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4.10.4 Conductor Ampacity

The ampacity of bare conductors is based on a number of factors, including the conductor material,

proximity of the conductors, climatic conditions, conductor temperature rise, emissivity, and altitude.

Copper conductors can carry about 1.3 or more times as much current as aluminum conductors of the

same size. However, based on weight, more than twice as much copper is required for the same

ampacity.

The current distribution of closely spaced conductors is affected by their mutual inductance in accordance

with the proximity effect. The additional losses attributed to this effect can usually be neglected if

conductor spacing is 45.7 centimeters (18 inches) or greater.

Climatic conditions have a great effect on conductor ampacity. Ampacities are usually determined based

on ambient temperatures of 40oC (104oF). For prolonged ambient temperatures above this value,

ampacities are usually reduced. Wind tends to reduce the temperature of outdoor bare conductors. An

assumed steady wind may be reasonable in many areas. The sun’s radiation can cause the temperature of

bare conductors to increase, which results in lower ampacities and should be considered in predominately

sunny locations.

Conductor temperature rise is the temperature increase above ambient at which the conductor is

operating. To prevent excessive surface oxidation and possible damage from annealing, the temperature

rise is usually limited to 30oC (54oF) for a total maximum conductor temperature of 70oC (158oF) under

normal operating conditions. The trend is toward higher operating temperatures. Temperature rises of

50oC (90oF) and higher have been used successfully. However, temperatures that could damage the

conductors or connected equipment should be avoided.

The conductor surface emissivity has an effect on conductor ampacity. For aluminum conductors,

emissivity is usually taken as 0.5 and for copper conductors 0.8. Both of these values are for heavily

weathered conductor surfaces. The ampacity is usually higher for greater emissivity.

According to ANSI Std. C37.30, “Definitions and Requirements for High-Voltage Air Switches,

Insulators, and Bus Supports,” equipment that depends on air for its cooling medium will have a higher

temperature rise when operated at higher altitudes than when operating at lower altitudes. For altitudes in

excess of 1000 meters (3300 feet), the correction factors listed in Table 4-10 should be applied. Consider

a conductor with an ampacity of 1000 amperes in a 40oC (104oF) ambient temperature with a 30oC (54oF)

temperature rise at an altitude of 1000 meters (3300 feet). If this conductor is to be used at a higher

altitude, the ampacity has to be corrected. At 5400 meters (18,000 feet), this conductor will have an

ampacity of 1000 x 0.910 = 910 amperes in an ambient temperature of 40oC (104oF) with a 30oF (54oF)

temperature rise. The conductor may be operated at 1000 amperes at 5400 meters (18,000 feet), provided

the ambient temperature does not exceed 40oC x 0.824 = 33oC (104oF x 0.824 = 85.7oF) and the

temperature rise does not exceed 30oC (54oF).

4.10.5 Bus Connections

4.10.5.1 General: It is customary to purchase rigid bus conductors in lengths ranging from 3.05

meters (10 feet) to 12.2 meters (40 feet). Sections need to be joined together for longer lengths. Taps are

required from buses to electrical equipment. Bus conductors need to be attached to support insulators.

For greatest reliability and lowest cost, the fewer the connections the better.
Bulletin 1724E-300

Page 161

Table 4-10: Altitude Correction Factors/Current. Ref. ANSI Std. C37.30-1992, Table 1.

Copyright © 1992. IEEE. All rights reserved.

Altitude

Meters (Feet)

Correction Factors

to Be Applied to

Current Rating*

Correction Factors

to Be Applied to

Ambient Temperature*

1000 (3300) 1.00 1.00

1200 (4000) 0.995 0.992

1500 (5000) 0.990 0.980

1800 (6000) 0.985 0.968

2100 (7000) 0.980 0.956

2400 (8000) 0.970 0.944

2700 (9000) 0.965 0.932

3000 (10,000) 0.960 0.920

3600 (12,000) 0.950 0.896

4200 (14,000) 0.935 0.872

4800 (16,000) 0.925 0.848

5400 (18,000) 0.910 0.824

6000 (20,000) 0.900 0.800

Note: Correction factors are currently being reviewed.

*The correction factors for current rating and ambient temperature should not be applied at the same

time.

The various substation bus connections can be made by using any of four main methods—bolting,

clamping, compressing, and welding—depending on the conductor type and material. Bolted connections

are utilized in connecting two or more flat surfaces together. Clamp-type connections generally involve

the use of special fittings fabricated to permit conductors to be joined together or connected to other

equipment. Compression connections are principally used for splicing or terminating flexible conductors.

Welded connections are used primarily with rigid aluminum conductors. Weldment fittings are available

that eliminate extensive conductor cutting and shaping prior to welding. Compression fittings are now

available for rigid tubular bus.

Whenever connectors are utilized for making electrical connections, they should be equivalent electrically

and mechanically to the conductors themselves. Substation connectors are designed, manufactured, and

tested in accordance with NEMA Std. CC1, “Electric Power Connectors for Substations.”

4.10.5.1.1 Bolted Connections: Bolted connections are the primary means of making connections to

equipment terminals. Bolted joints permit the disconnection of equipment for maintenance or

replacement.

The most common bolted connection involves joining a conductor to an equipment terminal. A terminal

lug is attached to the conductor by clamping, compressing, or welding, and the lug is bolted to the

equipment terminal.

When a copper conductor is connected to a flat copper or electrical bronze equipment terminal, a copper

or electrical bronze terminal lug is utilized. The lug is usually bolted to the equipment terminal with a

minimum of two 1⁄2-inch, 13 threads per inch, high-strength silicon bronze bolts normally torqued to

54.23 newton-meters (40 pound-feet). Silicon bronze flat washers are normally used under both the bolt

heads and the nuts.
Bulletin 1724E-300

Page 162

When an aluminum conductor is connected to a flat copper or electrical bronze equipment terminal, an

aluminum terminal lug is utilized. The lug is usually bolted to the equipment terminal with a minimum of

two 1⁄2-inch, 13 threads per inch, anodized aluminum bolts normally torqued to 33.9 newton-meters

(25 pound-feet). The bolts are usually aluminum alloy 2024-T4 and the nuts alloy 6061-T6. Flat washers

of aluminum alloy 2024-T4 are normally used under both the bolt heads and the nuts. An anti-oxidation

compound should also be considered for aluminum connections.

When a copper conductor is connected to a flat aluminum equipment terminal, a copper or electrical

bronze terminal lug is utilized. The lug is usually bolted to the equipment terminal with a minimum of

two 1⁄2-inch, 13 threads per inch bolts, normally of stainless steel or tin-plated high-strength silicon

bronze. Flat washers of the same material as the other hardware are used under both the bolt heads and

the nuts. Stainless steel spring washers are used between the flat washers and the nuts. Bolts are torqued

to the spring washer manufacturer’s recommendations.

When an aluminum conductor is connected to a flat copper or electrical bronze equipment terminal, an

aluminum terminal lug is utilized. The lug is usually bolted to the equipment terminal with a minimum of

two 1⁄2-inch, 13 threads per inch bolts, normally of stainless steel or tin-plated high-strength silicon

bronze. Flat washers of the same material as the other hardware are used under both the bolt heads and

nuts. Stainless steel spring washers are used between the flat washers and the nuts. Bolts are torqued to

the spring washer manufacturer’s recommendations.

For aluminum–copper connections, the copper component should be installed below the aluminum

component to prevent the copper salts from washing onto the aluminum. Additionally, the aluminum

component should be massive, compared with the copper component. It is recommended the copper

connector be tinned when connecting to aluminum connectors.

4.10.5.1.2 Clamp-Type Connections: A large variety of clamp-type electrical connectors are

available for both flexible and rigid conductors of copper and aluminum. Most clamp-type connectors

achieve their holding ability as a result of tightening a number of bolts. The quantities and sizes of bolts

used should be as listed in NEMA Std. CC1.

Copper or electrical bronze connectors should be utilized with copper conductors. All-aluminum

connectors should be used with aluminum conductors.

4.10.5.1.3 Compression Connections: Compression connections are used in splicing or installing

terminal lugs on flexible conductors and for round tubular aluminum conductors. All-aluminum

compression connectors should be used for aluminum conductors. Copper compression connectors

should be used for copper conductors.

For connection on flexible conductors, installation of compression connectors in a vertical position with

the lug down should be avoided to prevent the entrance of moisture and possible damage from freezing.

Compression connection on rigid or flexible conductors can be made under any weather condition. The

fitting is compressed using a portable hydraulic pump. It compresses the fitting radially 360 degrees. An

inspection gauge is then used to verify that the connection is acceptable.

Compression connectors should always be installed in strict accordance with the manufacturer’s

instructions concerning the quantity and location of compressions. Connectors designed for a minimum

of two circumferential compressions are recommended.
Bulletin 1724E-300

Page 163

4.10.5.2 Welded Connections: Welded connections are used primarily with round tubular aluminum

conductors. Use of the special fittings available simplifies the procedures to permit faster installation.

Properly made welded connections have resistances that are not appreciably higher than the conductors

themselves to eliminate conductor hot spots.

Welded aluminum connections are extensively used in the construction of large substations. Construction

costs are usually slightly less with welded than clamp-type connections. In smaller installations with

fewer connections, it may not be economically feasible to weld connections.

4.11 RIGID BUS DESIGN

4.11.1 General Considerations

The design of a rigid bus system involves many factors.

4.11.1.1 Bus Location in the Substation and Its Proximity to Other Equipment: Provide ample

clearance to permit equipment maintenance and removal. Situate the bus to allow entrance of

construction and maintenance equipment into the substation.

4.11.1.2 Future Substation Expansion: It is important to plan for future expansion by sizing and

positioning buses to facilitate modifications.

4.11.1.3 Conductor Selection: The bus conductors are selected based on ampacity, physical

properties, and cost. Select conductors so that they have sufficient size and capacity to withstand system

faults and overcurrents without damage from overheating.

4.11.1.4 Short-Circuit Conditions: During short circuits, large forces can be developed in the bus

system. The rigid bus design includes consideration of these forces to prevent damage during shortcircuit conditions. The bus centerline-to-centerline spacing and the short circuit current both have effects

on these forces.

4.11.1.5 Wind and Ice Load: If not properly considered, wind and ice loads can cause extensive

damage to bus conductors and insulators. The usual practice is to consider National Electrical Safety

Code loadings as a minimum. Also consider local conditions since they may necessitate the use of more

severe loading criteria.

4.11.1.6 Insulator Strength: Since the number of different insulator ratings is limited, exercise care in

the bus layout so that a practical system is achieved. The strength of the insulators required is based on

the total bus loading and particularly the short-circuit forces.

4.11.1.7 Conductor Sag: Limit the sag of the bus conductors in the design. A flat horizontal system

looks much neater than one with excessive sag. The conductor sag is influenced by the conductor weight

and section modulus, the span length, and the vertical loading.

4.11.1.8 Aeolian Vibration: Long conductor spans can be damaged by vibrations caused by winds.

Excessive conductor sag can add to this problem. Span lengths whose natural frequency is near that set

up by a wind that has a high recurrence should be avoided. Use dampering conductors or other devices in

the bus to minimize vibration.
Bulletin 1724E-300

Page 164

4.11.1.9 Conductor Expansion: As the temperature of the conductors increases, longitudinal

expansion occurs. If the bus system is not provided with means to absorb this expansion, insulators or

other connected equipment can be damaged. A wide temperature range is required to accommodate the

bus length when de-energized at the lowest design temperature up to the maximum bus operating

temperature.

4.11.1.10 Location of Conductor Couplers: Long buses usually require the use of more than one

section of conductor. Consequently, couplers have to be utilized to join the sections together. These

couplers have to be properly located to prevent damage from bus loading and short-circuit forces.

Plan the bus system carefully by considering these aspects and other factors as they may develop. This

section deals with the design of the conductor and support insulator systems. For data concerning

supporting structures, refer to Chapter 7.

4.11.2 Procedure for Rigid Bus Design

The following procedure can be used in designing a rigid bus system:

4.11.2.1 Material and Size Selection: Select the material and size of the bus conductors based on

continuous current requirements. In higher voltage systems with longer bus spans, the structural

capabilities of the conductors may be the factor that determines the conductor material and size.

However, the conductors selected have to be capable of carrying the required continuous current in any

case.

4.11.2.2 Spacing: Using Tables 4-7 and 4-8, determine the bus conductor centerline-to-centerline

spacing.

4.11.2.3 Short-Circuit Forces: Calculate the maximum short circuit forces the bus has to withstand.

These forces can be determined using Equation 4-4:

Equation 4-4

Where:

FSC = Maximum short-circuit force on center conductor for a three-phase flat bus configuration

of round or square tubular conductors with the conductors equally spaced, in newtons per

meter (pounds per foot)

KSC = Short-circuit force reduction factor (0.5 to 1.0; 0.67 recommended)

i = rms value of three-phase symmetrical short-circuit current, in amperes

D = Centerline-to-centerline spacing of bus conductors in centimeters (inches)

4.11.2.4 Loading: Determine the total bus conductor loading. Table 4-11 lists values for wind and ice

loading for the various loading districts defined in the National Electrical Safety Code. Consider these

values as minimum. Also consider extreme wind.

















= × = ×

D

i

F 37.4 10 K

D

i

F 13.9 10 K

2

SC

-7

SC

2

SC

-5

SC
Bulletin 1724E-300

Page 165

Table 4-11: NESC Conductor Wind and Ice Loads.*

Ref. IEEE Std. C2-1997, Table 250-1. Copyright © 1997. IEEE. All rights reserved.

Loading District

Load Heavy Medium Light

Radial thickness of ice in

millimeters (inches)

12.5 (0.50) 6.5 (0.25) 0

Horizontal wind pressure in

pascals (pounds per square

foot)

190 (4.0) 190 (4.0) 430 (9.0)

* Conductor loading is usually based on these criteria. However, in locations where more severe

conditions are frequent, the conductor loading should be based on actual local conditions.

The ice loading can be determined using Equation 4-5:

Equation 4-5

Where:

WI = Ice loading, in newtons per meter (pounds per foot)

d1 = Outside diameter of conductor with ice, in centimeters (inches) (determine ice thickness

from Table 4-11)

d2 = Outside diameter of conductor without ice, in centimeters (inches)

The wind loading can be determined using Equation 4-6:

Equation 4-6

Where:

FW = Wind loading, in newtons per meter (pounds per foot)

CD = Drag coefficient, see Figure 4-22

PW = Wind pressure, in pascals (pounds per foot2) (from Table 4-11)

d1 = Outside diameter of conductor with ice, in centimeters (inches)

The total bus conductor loading can be determined using Equation 4-7:

Equation 4-7

Where:

FT = Total bus conductor loading, in newtons per meter (pounds per foot)

FSC = Maximum short-circuit force, in newtons per meter (pounds per foot)

FW = Wind loading, in newtons per meter (pounds per foot)

WC = Conductor weight, in newtons per meter (pounds per foot) (if damping cables are used to

control conductor vibration, add the cable weight to the conductor weight)

WI = Ice loading, in newtons per meter (pounds per foot)

( ) ( ( ))

2

2

2

i 1

2

2

2

1 W 0.704 d d W 0.311d d

I

= − = −

( ) W D W 1 W D W 1F = 0.01C P d F = 0.083C P d

[( ) ( ) ]

2

1

2

C i

2

FT = FSC + FW + W + W
Bulletin 1724E-300

Page 166

Figure 4-22: Drag Coefficients for Structural Shapes. Ref. ANSI/IEEE Std. 605-1987, Table 1.

Copyright © 1987. IEEE. All rights reserved.

Equation 4-7 applies maximum wind and maximum ice at the same time. NESC and ANSI/IEEE Std. 605

apply these forces individually, which reduces FT. Engineering judgment based on site conditions and

design loads should determine the maximum loading conditions of the bus.
Bulletin 1724E-300

Page 167

4.11.2.5 Span or Support Spacing: Calculate the maximum bus span or support spacing. Maximum

bus support spacing can be determined using Equation 4-8:

Equation 4-8

Where:

LM = Maximum bus support spacing, in meters (feet)

KSM = Multiplying factor from Table 4-12

KSE = Multiplying factor from Table 4-12

FB = Maximum desirable fiber stress of conductor, in kilopascals (pounds per inch2)

For round tubular conductors of:

copper,

FB = 1.38 x 105 kPa (20,000 lb/in2)*

6061-T6 aluminum alloy,

FB = 1.93 x 105 kPa (28,000 lb/in2)*

6063-T6 aluminum alloy,

FB = 1.38 x 105 kPa (20,000 lb/in2)*

*Includes a safety factor of 1.25.

S = Section modulus of conductor, in centimeters3 (inches3)

FT = Total bus conductor loading, in newtons per meter (pounds per foot)

Table 4-12: Conductor Maximum Span and Deflection Multiplying Factors

(KSM, KSE, KDM, KDE)

Bus System KSM (KSE) KDM (KDE)

Conductor fixed both ends

(single span)

0.110 (1.0) 2.6 x 104(4.50)

Conductor fixed one end,

simply supported other end

(single span)

0.090 (0.82) 5.4 x 104(9.34)

Conductor simply supported

(single span)

0.090 (0.82) 1.3 x 105(22.5)

Conductor simply supported

(two equal spans)*

0.090 (0.82) 5.4 x 104(9.34)

Conductor simply supported

(three or more equal spans)*

0.096 (0.88) 6.9 x 104(11.9)

* Maximum deflection occurs in end spans.





































=

















=

2

1

T

B

M SE

2

1

T

B

M SM F

F S

 L K

F

F S

L K
Bulletin 1724E-300

Page 168

4.11.2.6 Deflection: Calculate the maximum vertical conductor deflection using Equation 4-9:

Equation 4-9

Where:

y = Maximum vertical conductor deflection, in centimeters (inches). (Limit this value to

1/200 of the span length. If the value calculated is greater than 1/200 of the span length,

select a conductor with a larger diameter or reduce the span length. Recalculate as

required.)

KDM = Multiplying factor from Table 4-12

KDE = Multiplying factor from Table 4-12

WC = Conductor weight, in newtons per meter (pounds per foot) (if damping cables are used to

control conductor vibration, add the cable weight to the conductor weight)

WI = Ice loading, in newtons per meter (pounds per foot)

L = Bus support spacing, in meters (feet)

E = Modulus of elasticity, in kilopascals (pounds per inch2)

I = Moment of inertia, in centimeters4 (inches4)

4.11.2.7 Cantilever Strength: Determine the minimum required support insulator cantilever strength

using Equation 4-10:

Equation 4-10*

Where:

WS = Minimum insulator cantilever strength, in newtons (pounds)

FSC = Maximum short-circuit force, in newtons per meter (pounds per foot)

FW = Wind loading, in newtons per meter (pounds per foot)

LS = One half of the sum of the lengths of the two adjacent conductor spans, in meters (feet)

*Equation 4-10 includes an insulator safety factor of 2.5. This results in the insulator’s working load

being equal to 40 percent of the insulator’s rated cantilever strength.

Select support insulators from Table 4-4 or 4-5 or from manufacturers’ data with cantilever strength

ratings equal to or greater than WS. If sufficiently high ratings are not available, it will be necessary to

modify the bus design. This can be done by increasing the centerline-to-centerline conductor spacing to

reduce the short-circuit forces or by decreasing the bus span lengths.

4.11.2.8 Thermal Expansion: Provide for thermal expansion of conductors. The amount of

conductor thermal expansion can be calculated using Equation 4-11:

( ) ( )















 +

=

+

=

EI

W W L

y K

EI

W W L

y K

4

C I

DE

4

C I

DM

( ) S SC W LS W = 2.5 F + F
Bulletin 1724E-300

Page 169

Equation 4-11

Where:

Δl = Conductor expansion, in centimeters (inches) (final length minus initial length)

α = Coefficient of linear thermal expansion:

For aluminum, α = 2.3 x 10-5 per degree Celsius (1.3 x 10-5 per degree Fahrenheit)

For copper, α = 1.7 x 10-5 per degree Celsius (9.2 x 10-6 per degree Fahrenheit)

l = Initial conductor length, in centimeters (inches) (at initial temperature)

ΔT = Temperature variation, in degrees Celsius (Fahrenheit) (final temperature minus initial

temperature)

Bus sections with both ends fixed without provision for conductor expansion should be avoided. Make

connections to power circuit breakers, power transformers, voltage transformers, and other device

bushings or terminals that could be damaged by conductor movement either with flexible conductors or

expansion-type connectors.

Connections to switches utilizing apparatus insulators may require the use of expansion-type terminal

connectors to prevent damage from excessive conductor expansion. Use of expansion-type terminals in

this situation depends on the bus configuration and location of other expansion points. It is recommended

that expansion fittings used on long horizontal buses be limited to those permitting longitudinal expansion

only.

It is usually desirable to limit the length of sections of continuous buses to 30.48 meters (100 feet) or less

to limit the amount of conductor expansion in each section. This can be done by fixing certain points in

the bus and permitting other points to move freely. An example of a typical bus system is diagrammed in

Figure 4-23.

Figure 4-23: Typical Bus System Illustrating Provisions for Conductor Thermal Expansion

The system illustrated in Figure 4-23 can freely expand as necessary and is free of “captured spans” that

permit no expansion. The locations of slip-fit and fixed bus supports and expansion-type couplers or bus

supports divide the bus into four sections, each of which will expand approximately the same total

Δ l = alΔT
Bulletin 1724E-300

Page 170

amount. If it is desirable to connect the end sections of the bus to other equipment, provide flexible

conductors or expansion-type connectors.

4.11.2.9 Couplers: Locate conductor couplers. The couplers used on rigid buses should be as long as

possible to provide maximum joint rigidity and strength. Clamp-type bolted couplers should have the

quantity and size of clamping bolts listed in NEMA Std. CC1. Welded couplers for aluminum conductors

should be of the internal type. Compression connectors should be appropriately sized and located.

To prevent conductor damage from bending caused by its own weight and external loads, carefully

position couplers. Welding and bolting can cause appreciable loss of conductor strength in the immediate

coupler locations. Consequently, position couplers where the least amount of bending will occur. The

ideal locations are points of zero bending moment along the conductor.

Table 4-13 lists the ideal locations for conductor couplers for continuous conductors.

Table 4-13: Ideal Locations for Couplers in Continuous Uniformly Loaded Rigid Conductors

Quantity

of Conductor Spans

Ideal Coupler Locations Measured to

the Right from the Left-most Support

1 *

2 0.750L, 1.250L

3 0.800L, 1.276L, 1.724L, 2.200L

4 0.786L, 1.266L, 1.806L, 2.194L

2.734L, 3.214L

5 0.789L, 1.268L, 1.783L, 2.196L,

2.804L, 3.217L, 3.732L, 4.211L

6 0.788L, 1.268L, 1.790L, 2.196L,

2.785L, 3.215L, 3.804L, 4.210L,

4.732L, 5.212L

L = Distance of the bus between the bus supports.

* The zero moment locations for single-span simply supported conductors are at the supports. Consequently,

couplers are not recommended.

If couplers have to be positioned in other than the ideal locations listed in Table 4-13, reduce the

maximum allowable fiber stress used in Section 4.11.2.5 by as much as 50 percent, depending on the

degree of variation from the ideal location, and recalculate the maximum span length used. If the span

length being considered exceeds this maximum, reduce it as necessary. Conductor couplers can now be

positioned wherever convenient.

4.11.2.10 Aeolian Conductor Vibration: Aeolian conductor vibration is primarily the result of

steady low-velocity transverse winds striking the conductor and causing it to vibrate. When the frequency

of the driving force (wind) is approximately equal to the natural frequency of the bus span, resonance

occurs. The resulting vibrations can cause insulator damage.

Vibrations will occur in almost all bus spans independently of the conductor material, diameter, or length.

In short spans, the vibrations are usually of small enough magnitude to be neglected. However, in spans

longer than about 6 meters (20 feet), methods for vibration damping should be considered.
Bulletin 1724E-300

Page 171

Two primary methods have been used to dampen aeolian vibrations. The first and most widely used

method consists of installing scrap cables in the horizontal buses. When this method is used, it is

necessary that the cables be loose in the bus tubing to permit vertical movement. If new cables are used,

they should be straightened prior to installation to prevent the cables from jamming against the tubing

sides. Additionally, end caps, preferably of the driven type, should be installed on the ends of the buses

containing the damping cables to prevent horizontal cable movement out of the tubing. To be effective,

damping cables should be installed for the entire bus length for buses where excessive vibration is

suspected.

The second method used to dampen aeolian vibrations consists of installing internal or external

prefabricated bus dampers on the bus conductors. Usually, one damper is installed in each bus span to

control the vibrations. Location and installation should be in accordance with the manufacturer’s

instructions.

4.11.3 Bus Design Example

Design a three-phase rigid bus with the following characteristics:

Total bus length: 45.72 meters (150 feet), assuming four equal spans of 11.43 m

(37.5 ft)

Voltage: 161 kV

BIL: 750 kV

Insulator type: post

Continuous current rating: 1800 amperes

Short-circuit current: 24,000 rms symmetrical amperes

Altitude: 304.8 m (1000 ft)

NESC loading: heavy

Disconnect switch connected to one end of bus

External prefabricated dampers to control conductor vibration

4.11.3.1 Material and Size Selection: Select the material and size of the bus conductors.

Based on the continuous current requirements, 7.6 cm (3 in.) IPS, schedule 40 6063-T6 aluminum alloy

(1890 amperes) is selected with the following properties:

WC (weight) = 38.2 N/m (2.62 lb/ft)*; see Table 4-14

d2 (outside diameter) = 8.89 centimeters (3.50 inches); see Table 4-14

I (moment of inertia) = 125.6 cm4 (3.017 in4); see Table 4-14

E (modulus of elasticity) = 6.9 x 107kPa (10 x 106 lb/in2)

S (section modulus) = 28.2 cm3 (1.72 in3); see Table 4-14

FB (maximum allowable fiber stress) = 1.38 x 105kPa (20,000 lb/in2)

* If damping cables are to be used to control conductor vibration, the cable weight has to be added to

the conductor weight. In this example, external prefabricated dampers will be used for vibration

control.
Bulletin 1724E-300

Page 172

Table 4-14: ASA Schedule 40 Aluminum Pipe Conductors Physical Properties. Hubbell Technical Data, Table 52.

Reprinted with permission of Anderson Electrical Products (Hubbell Power Systems, Centralia, Mo.).

NOMINAL DIAMETER

PIPE

SIZE IN. CM

WALL

THICKNESS AREA WT/FT WT/M

MOMENT OF

INERTIA

SECTION

MODULUS

RADIUS OF

GYRATION

IN. CM OUTSIDE INSIDE OUTSIDE INSIDE IN. CM IN.2 CM2LB N/M IN.4 CM4IN.3 CM3IN. CM

1⁄2 1.27 0.840 0.622 2.134 1.580 0.109 0.277 0.250 1.615 0.294 4.290 0.017 0.712 0.041 0.667 0.261 0.664

3⁄4 1.91 1.050 0.824 2.667 2.093 0.113 0.287 0.333 2.146 0.391 5.706 0.037 1.540 0.071 1.155 0.334 0.848

1 2.54 1.315 1.049 3.340 2.664 0.133 0.338 0.494 3.186 0.581 8.479 0.087 3.634 0.133 2.176 0.421 1.068

1 1⁄4 3.18 1.660 1.380 4.216 3.505 1.140 2.896 0.669 4.313 0.786 11.470 0.195 8.104 0.235 3.844 0.540 1.371

1 1⁄2 3.81 1.900 1.610 4.826 4.089 1.145 2.908 0.800 5.158 0.940 13.718 0.310 12.899 0.326 5.345 0.623 1.581

2 5.08 2.375 2.067 6.033 5.250 0.154 0.391 1.075 6.932 1.264 18.446 0.666 27.709 0.561 9.187 0.787 1.999

2 1⁄2 6.35 2.875 2.469 7.303 6.271 0.203 0.516 1.704 10.994 2.004 29.245 1.530 63.683 1.064 17.436 0.947 2.406

3 7.62 3.500 3.068 8.890 7.793 0.216 0.549 2.229 14.377 2.621 38.249 3.017 125.577 1.724 28.251 1.164 2.957

3 1⁄2 8.89 4.000 3.548 10.160 9.012 0.226 0.574 2.680 17.287 3.151 45.983 4.788 199.292 2.394 39.231 1.337 3.396

4 10.16 4.500 4.026 11.430 10.226 0.237 0.602 3.174 20.477 3.733 54.476 7.232 301.019 3.214 52.668 1.510 3.835

5 12.70 5.563 5.047 14.130 12.819 0.258 0.655 4.300 27.741 5.057 73.798 15.160 631.007 5.451 89.326 1.878 4.770

6 15.24 6.625 6.065 16.828 15.405 0.280 0.711 5.581 36.009 6.564 95.790 28.150 1171.691 8.498 139.257 2.245 5.702
Bulletin 1724E-300

Page 173

4.11.3.2 Spacing: Determine the bus conductor centerline-to-centerline spacing from Table 4-7:

D (bus centerline-to-centerline spacing) = 274 cm (108 in.)

4.11.3.3 Short-Circuit Forces: Calculate the maximum short circuit force:

4.11.3.4 Loading: Determine the total bus conductor loading:

From Table 4-9, Radial thickness of ice: 1.27 cm (0.50 in.)

Horizontal wind pressure: 191.5 Pa (4.0 lb/ft2)

4.11.3.5 Support Spacing: Calculate the maximum bus support spacing:

( )( )

F 195.8 N/m

274

24,000

F 13.9 10 0.67

D

i

F 13.9 10 K

SC

2

5

SC

2

SC

5

SC

=













= ×

= ×

−

−

( )( )

( )

2

SC

2

7

SC

2

SC

7

SC

F 13.4 lb/ft

108

24,000

F 37.4 10 0.67

D

i

F 37.4 10 K

=





























= ×

















= ×

−

−

( )

( )[( ) ( ) ]

W 36.3 N/m

W 0.704 11.43 8.89

W 0.704 d d

I

2 2

I

2

2

2

I 1

=

= −

= − ( ( ))

( [( ) ( ) ])

(W 2.49 lb/ft)

W 0.311 4.50 3.50

W 0.311 d d

I

2 2

I

2

2

2

I 1

=

= −

= −

( )( )( )

F 21.9 N/m

F 0.01 191.5 11.43

F 0.01 P d

W

W

W W 1

=

=

= ( )

( ( )( )( ))

(F 1.49 lb/ft)

F 0.083 4.0 4.50

F 0.083 P d

W

W

W W 1

=

=

=

[( ) ( ) ]

[( ) ( ) ]

230.1N/m

195.8 21.9 38.2 36.3

2

1

2 2

2

1

2 2

=

= + + +

= + + +

T

T

T SC W C I

F

F

F F F W W [( ) ( ) ]

[( ) ( ) ]

(F 15.6 lb/ft)

F 13.3 1.49 2.62 2.49

F F F W W

T

2

1

2 2

T

2

1

2

C I

2

T SC W

=













= + + +













= + + +

2

1

T

B

M SM F

F S

L K 











=

































=

2

1

T

B

M SE F

F S

L K
Bulletin 1724E-300

Page 174

Four equal spans of 11.43 meters (37.5 feet) were assumed. From Table 4-12, KSM = 0.096 (KSE = 0.88)

for three or more equal spans.

The assumed spacing of 11.43 meters (37.5 ft) is structurally permissible for the conductors.

4.11.3.6 Deflection: Calculate the maximum vertical conductor deflection:

Four equal spans of 11.43 meters (37.5 feet) were assumed. From Table 4-12, KDM = 6.9 x 104 (KDE =

11.9) for three or more equal spans.

Maximum permissible deflection is 1/200 of the span length:

Since the calculated deflection is greater than the maximum permissible deflection, the design has to be

modified. The span length will be reduced to five equal spans of 9.14 meters (30 feet) each. The

maximum vertical deflection is then recalculated.:

Maximum permissible deflection is:

( )

( )( )

L 12.48m

230.1

1.38 10 28.2

L 0.096

M

2

1

5

M

=











 ×

=

( )

( )( )

( )

(L 41.3ft)

15.6

20,000 1.72 L 0.88

M

2

1

M

=

































=

( ) ( )















 +

=

+

=

EI

W W L

 y K

EI

W W L

y K 

4

C I

DE

4

C I

DM

( )

( )( )

( )( )

( )

( )( )

( )( )

y 10.1 cm (y 3.99 in.)

10 10 3.017

2.62 2.49 37.5

 y 11.9

6.9 10 125.6

38.2 36.3 11.43

y 6.9 10 

6

4

7

4

4

= =

















×

+

=

×

+

= ×

( )( ) ( )( )

y 5.72 cm (y 2.25 in.)

200

37.5 12

 y

200

11.43 100

y

max

max max

= =













= =

( )

( )( )

( )( )

( )

( )( )

( )( )

4.14 cm (y 1.63 in.)

10 10 3.017

2.62 2.49 30

 y 11.9

6.9 10 125.6

38.2 36.3 9.14 6.9 10 

6

4

7

4

4

= =

















×

+

=

×

+

= ×

y

y

( )( ) ( )( )

4.57 cm (y 1.80 in.)

200

30 12

 y

200

9.14 100

max max

max max

= =













= =

y

y
Bulletin 1724E-300

Page 175

Since the calculated value with 9.14 m (30 ft) support spacing is less than the maximum permissible

deflection, this support spacing is adequate.

4.11.3.7 Cantilever Strength: Determine the minimum required support insulator cantilever strength:

From Table 4-5, select Technical Reference Number 291 for 5338 newtons (1200 pounds) cantilever

strength post type insulators.

4.11.3.8 Thermal Expansion: Provide for conductor expansion:

Assuming a total conductor temperature variation of 50oC (90oF), the total conductor expansion is:

Some means has to be provided to account for this change. Figure 4-24 illustrates one method that can be

used that permits free expansion in all spans.

Figure 4-24: Coupler Location

( ) ( ( ) )

( )( ) ( )

W 4974N (W 1109 lb)

2

30

2

30

 W 2.5 13.3 1.49

2

9.14

2

9.14 W 2.5 195.8 21.9

W 2.5 F F L W 2.5 F F L

S S

S S

S SC W S S SC W S

= =





























 = + +











= + +

= + = +

( )

( )( )( )( ) ( ( )( )( )( ))

5.26 cm ( 2.11 in.)

2.3 10 45.72 100 50 1.3 10 150 12 90

 

-5 -5

Δ = Δ =

Δ = × Δ = ×

Δ = Δ Τ Δ = Δ Τ

l l

l l

l al l al
Bulletin 1724E-300

Page 176

4.11.3.9 Couplers: Locate conductor couplers:

From Table 4-13, the ideal coupler locations for the five-span bus of 9.14-meter (30-foot) spans measured

to the right from the left-most support are as follows:

1 7.2 m (23.7 ft)

2 11.6 m (38.0 ft)

3 16.3 m (53.5 ft)

4 20.1 m (65.9 ft)

5 25.6 m (84.1 ft)

6 29.4 m (96.5 ft)

7 34.1 m (112.0 ft)

8 38.5 m (126.3 ft)

These locations are illustrated in Figure 4-25. Assuming that the bus conductor is available in

12.19-meter (40-foot) lengths, the couplers should be positioned at points 2, 4, 6, and 8. The conductor

lengths are cut as required to position the couplers at these approximate locations.

Legend:

SF = Slip-fit bus support

F = Fixed bus support

EX = Expansion terminal

Figure 4-25: Bus Configuration for Example

4.11.3.10 Aeolian Vibration: Since the spans are fairly long, damaging vibrations may occur.

Consequently, a means for controlling the vibrations should be provided. Prefabricated dampers can be

attached to the buses or scrap cables can be installed in the buses. If cables are used, the cable weight has

to be added to the conductor weight for the bus calculations.

4.12 STRAIN BUS DESIGN

4.12.1 General Considerations

Strain bus design involves many factors.

4.12.1.1 Bus Location in the Substation and Its Proximity to Other Equipment: The flexible

conductors used for strain bus construction permit significant conductor movement. Consequently, the

conductors have to be carefully positioned to prevent contact with other equipment and infringement upon

minimum electrical clearances under all loading and climatic conditions. Equipment maintenance and

removal should also be considered in locating buses and support structures.
Bulletin 1724E-300

Page 177

4.12.1.2 Future Substation Expansion: Strain buses usually require large supporting structures.

These structures can limit future expansion if not properly positioned.

4.12.1.3 Conductor Selection: The conductor is selected based on ampacity, physical properties, and

cost. Conductors have to be selected so that they have sufficient size and capacity to withstand system

faults and overcurrents without damage from overheating.

4.12.1.4 Wind and Ice Load: Wind and ice can increase conductor sags and tensions appreciably.

The usual practice is to consider National Electrical Safety Code loadings as a minimum. Local

conditions should be considered since they may necessitate the use of more severe loading criteria.

4.12.1.5 Insulator Strength: The suspension insulators are selected based on the anticipated

maximum loading conditions. The maximum loading for porcelain insulators should not exceed 40

percent of the mechanical–electrical strength ratings listed in RUS IP 202-1. The maximum loading for

fiberglass insulators may not exceed 40 percent of the manufacturer’s strength ratings.

4.12.1.6 Span Length: The span length influences the conductor sag. As the span length increases,

the sag increases if the same tension is maintained. To limit the sag, the tensions can be increased.

Springs can also be used to limit the tension and sag.

4.12.1.7 Sag and Tension: Strain buses are usually positioned above other substation equipment.

Conductor breakage could result in equipment damage or outage. To prevent breakage and to minimize

support structure size, the conductors are usually installed at tensions of approximately 13,350 newtons

(3000 pounds) or less. Sag may increase because of the deflection of support structures.

4.12.1.8 Temperature Variations: Temperature variations cause changes in conductor lengths. As

conductor temperature increases, the sag increases and the tension decreases.

4.12.1.9 Tap Loads: Taps from the conductors to other buses or equipment should be limited in

tension to prevent damage to equipment. The taps are usually installed as slack connections.

4.12.2 Procedure for Strain Bus Design

The following procedure can be used to design a strain bus system:

4.12.2.1 Material and Size Selection: Select the material and size of the bus conductors, based on

continuous current requirements.

4.12.2.2 Spacing: Using Tables 4-7 and 4-8 from Section 4.9, determine the bus conductor centerlineto-centerline spacing. As explained in Section 4.9, the minimum metal-to-metal, bus centerline-tocenterline, and minimum ground clearances listed in Table 4-7 should be increased at least 50 percent for

nonrigid conductors.

4.12.2.3 Suspension Insulators: Select the quantity of suspension insulators from Table 4-6.

4.12.2.4 Loading: Determine the total bus conductor loading. Table 4-15 lists values for wind and ice

loading for the various loading districts defined in the National Electrical Safety Code. These values

should be considered as minimum.
Bulletin 1724E-300

Page 178

Table 4-15: NESC Conductor Loading Criteria.* Ref. ANSI Std. C2-1997, Tables 250-1 and 251-1.

Copyright © 1997. IEEE. All rights reserved.

Loading District

Load Heavy Medium Light

Radial thickness of ice in

millimeters (inches)

12.5 (0.50) 6.5 (0.25) 0

Horizontal wind pressure in

pascals (pounds per square foot)

190 (4.0) 190 (4.0) 430 (9.0)

Temperature in degrees Celsius

(degrees Fahrenheit)

–20 (0) –10 (+15) -1.0 (+30)

Constant (k) to be added to the

resultant

4.4 (0.30) 2.5 (0.20) 0.73 (0.05)

* Conductor loading is usually based on these criteria. However, in locations where more severe

conditions frequently occur, the conductor loading should be based on actual local conditions.

The ice loading can be determined from Equation 4-12:

Equation 4-12

Where:

WI = Ice loading, in newtons per meter (pounds per foot)

d1 = Outside diameter of conductor with ice, in centimeters (inches) (determine ice thickness

from Table 4-15)

d2 = Outside diameter of conductor without ice, in centimeters (inches)

The wind loading can be determined using Equation 4-13:

Equation 4-13

Where:

FW = Wind loading, in newtons per meter (pounds per foot)

PW = Wind pressure, in pascals (pounds per foot2) (from Table 4-15)

d1 = Outside diameter of conductor with ice, in centimeters (inches) (determine ice thickness

from Table 4-15)

The total bus conductor loading can be determined using Equation 4-14:

Equation 4-14

Where:

FT = Total bus conductor loading, in newtons per meter (pounds per foot)

FW = Wind loading, in newtons per meter (pounds per foot)

WC = Conductor weight, in newtons per meter (pounds per foot)

( ) ( ( ))

2

2

2

I 1

2

2

2 WI = 0.704 d1 − d W = 0.311 d − d

( ) W 1 W 1F 0.01P d F 0.083P d W W= =

F [F (W W ) ] k T W C I= + + +

2

1

2 2
Bulletin 1724E-300

Page 179

WI = Ice loading, in newtons per meter (pounds per foot)

k = NESC constant (from Table 4-15)

4.12.2.5 Conductor Sag: Calculate or obtain the maximum conductor sag. Methods for this

calculation can be found in conductor manufacturers’ literature. In some cases the maximum sag may

occur during the most severe loading condition. For substation strain buses, the design tension is usually

limited to 13,350 newtons (3000 pounds) per conductor under the most severe loading to minimize the

size of support structures. These conductor tensions have to be coordinated with the support structure

designs to ensure compatibility under all loading conditions. The tensions that will occur under unloaded

conditions will be considerably less than the maximum.

For light loading conditions where ice loads are not considered, the maximum conductor sag may occur at

the highest conductor temperature when the conductor length is at a maximum. For other loading

conditions, sags should be determined for both high conductor temperatures and maximum loading so that

adequate clearance from other equipment can be provided.

4.12.2.6 Suspension Insulator Effect: Calculate the suspension insulator effect on conductor sag. For

short dead-ended spans, such as substation strain buses, the suspension insulators can have an appreciable

effect on span sags. The following procedure can be used to calculate the insulator effect, which is added

to the conductor sag for the total bus sag. See Figure 4-26.

I C

I AC BC

I

AC

AC I

I

AC

AC I

I

BC

AC AB I

I

BC I

BD AB

C

I

BC

C

C

C

IN

C

I

Y Y Y

Y Y Y

C

X

Y C

C

X C

C

X

C

C

Y C

L

X Assume

C

C

X

W

T

C

W

T

C

= +

= −

















−

















=

















=

















= +

















−















=













= = −

=

=

cosh 1

sinh

sinh

1

X

cosh

2

X

-1

BC

BD

l

l l

l
Bulletin 1724E-300

Page 180

Where:

CI = Insulator catenary constant, in meters (feet)

CC = Conductor catenary constant, in meters (feet)

XAC = Horizontal distance from insulator support point to center of insulator catenary, in meters

(feet)

XBC = Horizontal distance from connection point of insulator string and conductor to center of

insulator catenary, in meters (feet)

XBD = Horizontal distance from connection point of insulator string and conductor to center of

conductor catenary, in meters (feet)

ΡAB = Length of insulator string, in meters (feet)

ΡAC = Arc length from insulator support point to center of insulator catenary, in meters (feet)

Y = Total bus sag

YAC = Sag from insulator support point to center of insulator catenary, in meters (feet)

YBC = Sag from connection point of insulator string and conductor to center of insulator

catenary, in meters (feet)

YI = Insulator sag, in meters (feet)

YC = Conductor sag, in meters (feet)

y = Total bus sag, including insulators and conductor, in meters (feet)

TC = Horizontal conductor tension, in newtons (pounds)

WIN = Insulator string weight, in newtons per meter (pounds per foot)

WC = Conductor weight, in newtons per meter (pounds per foot)

L = Span length, in meters (feet)

Figure 4-26: Short Strain Bus Insulator Effect
Bulletin 1724E-300

Page 181

4.12.2.7 Stringing Tensions and Corresponding Sags: Calculate and chart stringing tensions and

corresponding sags for a range of conductor temperatures expected during installation. Base the

calculations on the assumed maximum tension that occurs under the most severe conductor loading.

Include in the chart and list on the installation drawings span length, tension, and total bus sag for various

conductor temperatures. Methods to determine the sags and tensions can be found in conductor

manufacturers’ literature.

After the conductor sags are calculated, add the suspension insulator sag to the conductor sags to

determine the total bus sags as described in Section 4.12.

4.12.2.8 Sample Calculation of Bus Conductor Loading: Calculate the total bus conductor loading

for the following strain bus:

Span length: 60.96 meters (200 feet)

Voltage: 161 kV

BIL: 750 kV

Conductor size: 795 kcmil 26/7 ACSR

Conductor diameter: 2.81 cm (1.108 in.)

Conductor weight: 16.0 N/m (1.094 lb/ft)

NESC loading: heavy

Ice loading: Select ice thickness from Table 4-15:

Wind loading: Select wind pressure from Table 4-15:

( ) ( ( ))

( )[( ) ( ) ] ( )[( ) ( ) ]

W 14.6 N/m (W 1.0 lb/ft )

W 0.704 5.31 2.81 W 0.311 2.108 1.108

W 0.704 d d W 0.311 d d

I I

2 2

I

2 2

I

2

2

2

I 1

2

2

2

I 1

= =

= − = −

= − = −

( )

( ) ( ) ( ( )( )( ))

F 10.2 N/m (F 0.70 lb/ft )

F 0.01 (190.0) 5.31 F 0.083 4 2.108

F 0.01P d F 0.083P d

W W

W W

W W 1 W W 1

= =

= =

= =
Bulletin 1724E-300

Page 182

Total bus conductor loading:

4.12.2.9 Sample Calculation of Suspension Insulator Effect on Bus Sag: Calculate the suspension

insulator effect on bus sag for the following strain bus:

Span length: 60.96 meters (200 feet)

Voltage: 161 kV

BIL: 750 kV

Conductor size: 795 kcmil 26/7 ACSR

Conductor diameter: 2.81 cm (1.108 in.)

Conductor weight: 16.0 N/m (1.094 lb/ft)

Conductor tension: 8896 N (2000 lb)

Number of suspension insulators (from Table 4-6): 10

Length of each insulator: 14.6 cm (5.75 in.)

Weight of each insulator: 48.9 N (11.0 lb)

[ ( ) ] [ ( ) ]

[( ) ( ) ] [( ) ( ) ]

F 36.6 N/m (F 2.51lb/ft)

F 10.2 16.0 14.6 4.38 F 0.70 1.094 1.0 0.30

F F W W k F F W W k

T T

2

1

2 2

T

2

1

2 2

T

2

1

2

C I

2

T W

2

1

2

C I

2

T W

= =













= + + + = + + +













= + + + = + + +

















= =

IN

C

IN

C

I W

T

W

T

C CI 

















































=

























=

12

1

5.75

11

2000

 C

100

1

14.6

48.9

8896

CI I

( )

















= =

= =

C

C

C

C

C

I

W

T

W

T

C

C

C

I

 C

26.6 m C 87.1ft
Bulletin 1724E-300

Page 183

( )

































−

















=

















−

















=

= =

1 y cosh 1

C

x

cosh

1.39 m x 4.54 ft

BC

I

BC

BC

I

BC

BC I I

BC

C

x

y C C

x

( ) ( )

y 0.0363m (y 0.118 ft)

1

87.1

4.54 1 y 87.1 cosh

26.6

1.39

y 26.6 cosh

BC BC

BC BC

= =





























 −











= 











 −











=

( ) ( ) ( ) ( )

2.85 m ( 9.33 ft)

87.1

4.54 87.1 sinh

12

5.75

 10

26.6

1.39 26.6 sinh

100

14.6

10

C

x

 sinh 

C

x

sinh

AC

AC

I

BC

AC

I

BC

= =





























 +











 =











 +











=

































= + 















= +

l l

l l

l l l l

AC

AC

AC AB CI AB CI

556 m (C 1828 ft)

1.094

2000

 C

16

8896

C

C

= =













= =

C

C

C

C

( )( ) ( )( )





























 = −











= −

















= =

12

10 5.75

 

2

200

1828

87.1

 x

100

10 14.6

 

2

60.96

555

26.6

 x

BC

BC

BC

BD

C

I

BD

C

I

BC

x

x

C

C

x

C

C

x
Bulletin 1724E-300

Page 184

The value calculated for YI is then added to the conductor sag to determine the total bus sag. Use 2xBD as

the span length to calculate the conductor sag.

4.13 APPLICATION OF MOBILE TRANSFORMERS AND SUBSTATIONS

Mobile transformers or mobile substations can be used to provide temporary service during equipment

maintenance, construction, emergency, or high load periods. Sufficient mobile units strategically placed

can reduce or eliminate the requirements for on-site spare transformers.

Several aspects should be considered in applying mobile transformers or substations:

1. Size and maneuverability of the equipment

2. Installation location and provisions

3. Electrical clearances

4. Primary and secondary connections

5. Grounding

( )

( )

0.116 m (Y 0.38ft)

0.152 0.0363 y 0.498 0.118

 y

I

I

I

= =

= − = −

= − = −

I

I

I AC BC AC BC

Y

y

y y y y y

( ) ( )

0.152 m (y 0.498ft)

1

87.1

9.31 1 y 87.1 cosh

26.6

2.84 26.6 cosh

cosh 1 y cosh 1

AC

AC

AC

= =





























 −











= 











 −











=





























−















 =











−















=

AC

AC

I

AC

I

I

AC

AC I

y

y

C

x

C

C

x

y C

( ) ( )

2.84 m (x 9.31ft)

87.1

9.33

 x 87.1 sinh

26.6

2.85 26.6 sinh

sinh x sinh

AC

1

AC

1

1

AC

-1

= =





























 =











=

































= 















=

− −

−

AC

AC

I

AC

I

I

AC

AC I

x

x

C

C

C

x C

l l
Bulletin 1724E-300

Page 185

6. Auxiliary system requirements

7. Safety

4.13.1 Size and Maneuverability of the Equipment

One of the primary advantages of mobile equipment is its ability to be used at more than one location. To

accommodate installation, adequate space has to be available to position and connect the equipment at all

intended locations. It may be impossible to use larger units in some locations without substantial

modifications because of the lack of sufficient space.

Substation entrances and access roads should be evaluated before committing particular equipment to the

location in question. Prior planning can save much time and facilitate installation.

4.13.2 Installation Location and Provisions

The mobile transformer or substation location should permit primary and secondary connections as short

as possible to the permanent substation equipment. It is desirable to utilize bare conductors for the

connections. Sometimes, insulated cables can be used where electrical clearances cannot be maintained

or where connections are long. The location should permit any required connections to be made quickly

and safely without disturbing adjacent equipment. The ease and speed of installation can be influenced

by the proximity of energized equipment.

Substations for which mobile equipment has been designated should have provisions for installation of

the equipment. The provisions can simply be terminals on permanent substation equipment or buses for

connecting the mobile equipment. It may be desirable to include bus extensions and/or disconnect

switches in some substations to facilitate the connections, particularly if they may be made while the

substation is energized.

If low-voltage ac or dc supplies are required, permanent facilities can be provided in the vicinity of where

the mobile equipment will be positioned. A weatherproof cabinet containing any necessary terminal

blocks, switches, or protective devices can be provided for terminating the low-voltage circuits.

Temporary connections can be made from this cabinet to the control cabinet on the mobile equipment.

Connections into the substation alarm system can also be provided in this or another cabinet. Terminal

blocks, test switches, indicating lamps, or any other necessary equipment can be located in the cabinet.

Provisions for grounding the equipment can consist of terminals or ground rods connected to the main

grounding grid.

4.13.3 Electrical Clearances

Maintaining adequate electrical clearances between the mobile equipment, its connections, and other

equipment is of prime importance. Installation using bare conductors should not be considered for a

location unless the minimum clearances listed in Tables 4-7 and 4-8 can be maintained. Insulated

conductors can be used in some locations if the minimum clearances cannot be maintained.

4.13.4 Primary and Secondary Connections

All primary and secondary connections should be as short as possible and should be made with bolted

connections. If possible, use bare conductors. However, for situations where minimum electrical

clearances cannot be maintained or where connections are long, insulated conductors can be employed.
Bulletin 1724E-300

Page 186

Conductors used should be sized to carry the maximum loads expected without overheating and to sustain

anticipated fault currents without damage. They should be checked for sufficient length before

connecting either end.

Temporary poles or structures may be required in some locations to facilitate the connections and

maintain clearances. It is desirable to store any necessary equipment not part of the mobile unit at the

substations, where required.

4.13.5 Grounding

Adequate grounding of mobile transformers and substations is extremely important for safe operation. At

least two independent connections should be made between the trailer and the ground system. The

mobile equipment should be connected to the substation ground grid whenever it is close to the

substation. In situations where the mobile is located a long distance from the substation and connection

to the substation ground grid is impractical, a separate ground system has to be provided.

4.13.6 Auxiliary System Requirements

Mobile unit transformers are usually designed for forced-cooled operation. Some units can provide the

low voltage necessary for auxiliary equipment operation through the use of on-board supply transformers

and equipment. For units without these provisions, low-voltage supplies can be obtained from the

substation station service system.

Before the substation station service system is used to supply mobile unit auxiliary systems, the voltage(s)

required by the auxiliary systems has to be checked against those available at the substation for

compatibility. The system should also be checked for adequate capacity.

If an external dc supply is necessary for power or control applications, the substation control battery can

be used. The system should be checked for proper voltage and adequate capacity prior to utilization.

4.13.7 Safety

Unless the mobile equipment is completely contained within another fenced area, a separate fence should

be provided to surround the equipment. The fence has to provide the same security and protection as

would a permanent substation fence. Gates should be provided with adequate locking facilities.

Mobile equipment usually requires some assembly during installation. Barriers and supports may require

installation. Some supporting members or braces used to protect the equipment during transit may have

to be removed. Assembly and installation should be in strict accordance with the manufacturer’s

instructions.

The equipment should be positioned on a level site and blocked to prevent movement. Ground slope at

the installation location should not exceed the manufacturer’s recommendations.

4.14 REFERENCES

Aluminum Company of America, Alcoa Aluminum Bus Conductor Handbook . Pittsburgh: Aluminum

Company of America, 1957.
Bulletin 1724E-300

Page 187

Anderson Electric Corporation, Technical Data: A Reference for the Electrical Power Industry. Leeds,

Ala.: Anderson Electric Corporation, 1964.

ANSI Std. C2, National Electrical Safety Code.

ANSI Std. C29.1, “Test Methods for Electrical Power Insulators.”

ANSI Std. C29.2, “American National Standard for Wet-Process Porcelain Insulators (Suspension

Type).”

ANSI Std. C29.8, “American National Standard for Wet-Process Porcelain Insulators (Apparatus, Cap

and Pin Type).”

ANSI Std. C29.9, “American National Standard for Wet-Process Porcelain Insulators (Apparatus, Post

Type).”

ANSI Std. C37.30, “Definitions and Requirements for High-Voltage Air Switches, Insulators, and Bus

Supports.”

ANSI Std. C37.32, “Schedules of Preferred Ratings, Manufacturing Specifications, and Application

Guide for High-Voltage Air Switches, Bus Supports, and Switch Accessories.”

ANSI Std. C62.2, “Guide for Application of Valve-Type Lightning Arresters for Alternating-Current

Systems.”

ANSI Std. C119.4, “American National Standard for Electric Connectors—Connectors for Use Between

Aluminum-to-Aluminum or Aluminum-to-Copper Bare Overhead Conductors.”

ANSI/IEEE Std. 605, “IEEE Guide for Design of Substation Rigid-Bus Structures.”

ASTM Std. B231, “Specification for Concentric-Lag-Stranded Aluminum 1350 Conductors [Metric].”

Beck, E., Lightning Protection for Electric Systems. New York: McGraw-Hill Book Co., 1954.

Eaton, J.R., Electric Power Transmission Systems. Englewood Cliffs, N.J.: Prentice Hall, Inc., 1972.

Giles, R.L., Layout of E.H.V. Substations. London: Cambridge University Press, 1970.

Golde, R.H., Lightning Protection. London: Edward Arnold Publishers Ltd., 1973.

IEEE Std. 998, “Guide for Direct Lightning Stroke Shielding of Substations.”

IEEE Std. 1119, “Guide for Fence Safety Clearances in Electric-Supply Stations.”

IEEE, Transmission Substations Subcommittee. Transaction Paper T-72-131-6 (Vol. 5).

Lewis, W.W., The Protection of Transmission Systems Against Lightning. New York: Dover

Publications, Inc., 1965.
Bulletin 1724E-300

Page 188

National Fire Protection Association, National Electrical Code 1996. Boston: National Fire Protection

Association, 1995.

NEMA Std. CC1, “Electric Power Connectors for Substations.”

NEMA Std. HV2, “Application Guide Porcelain Suspension Insulators.”

NEMA Std. SG6, “Power Switching Equipment.”

RUS Bulletin 1724D-114, “Voltage Regulator Application on Rural Distribution Systems.”

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”

The Aluminum Association, Aluminum Electrical Conductor Handbook. New York: The Aluminum

Association, 1971.

Westinghouse Electric Corporation, Electric Utility Engineering Reference Book. Vol. 3. East

Pittsburgh, Pa.: Westinghouse Electric Corporation, 1965.

Westinghouse Electric Corporation, Electrical Transmission and Distribution Reference Book. 4

th ed.

East Pittsburgh, Pa.: Westinghouse Electric Corporation, 1964.

Westinghouse Electric Corporation, Surge Protection of Power Systems. East Pittsburgh, Pa.:

Westinghouse Electric Corporation, 1975.

4.15 LEGEND FOR EQUATIONS

CC Conductor catenary constant

CD Drag coefficient for structural shapes

CI Insulator catenary constant

D Centerline-to-centerline spacing of bus conductors

d1 Outside diameter of bus conductor with ice

d2 Outside diameter of bus conductor without ice

E Modulus of elasticity

WC Bus conductor weight per unit length

WI Ice loading on bus conductor per unit length

WIN Insulator string weight per unit length

FSC Short-circuit force on bus conductor per unit length

FB Maximum desirable bus conductor fiber stress

FT Total bus conductor loading per unit length

FW Wind loading on bus conductor per unit length

I Moment of inertia

i Short-circuit current

k NESC conductor loading constant

KSC Short-circuit force reduction factor

KDE Multiplying factor for maximum vertical conductor deflection (inches)
Bulletin 1724E-300

Page 189

KDM Multiplying factor for maximum vertical conductor defle ction (centimeters)

KSE Multiplying factor for maximum bus support spacing (inches)

KSM Multiplying factor for maximum bus support spacing (centimeters)

L Bus span length

LM Maximum bus support spacing

LS Conductor length for calculating insulator cantilever strength

Δ Ρ Conductor expansion (final length minus initial length)

Ρ Initial conductor length

ΡAB Length of insulator string

ΡAC Arc length from insulator support point to center of insulator catenary

PW Wind pressure on projected area of bus conductor

S Bus conductor section modulus

ΔT Bus conductor temperature variation (final temperature minus initial temperature)

TC Horizontal bus conductor tension

WS Minimum insulator cantilever strength

XAC Horizontal distance from insulator support point to center of insulator catenary

XBC Horizontal distance from connection point of insulator string and conductor to center of

insulator catenary

XBD Horizontal distance from connection point of insulator string and conductor to center of

conductor catenary

y Total bus sag or deflection

YAC Sag from insulator support point to center of insulator catenary

YBC Sag from connection point of insulator string and conductor to center of insulator

catenary

YI Insulator sag

YC Conductor sag

Ymax Maximum permissible conductor deflection

α Coefficient of linear thermal expansion
Bulletin 1724E-300

Page 190

(BLANK PAGE)
Bulletin 1724E-300

Page 191

CHAPTER 5

MAJOR EQUIPMENT

5.1 GENERAL

Major electrical equipment in a substation is generally categorized by longer delivery time, manufacture

only after receipt of a purchase order, custom design to some degree, and much greater cost per unit

than minor items such as insulators, bare wire, and conduit.

The specifications for such are determined not only by its relationship to other equipment in the

substation but also by pre-established system conditions and performance requirements. The following

sections in this chapter deal with the many possible variations in equipment. Procurement of major

pieces of equipment usually depends on a detailed technical specification often developed after

consultation with vendors.

Selection of the major equipment requires the utmost consideration. Cost, schedule, and performance

penalties may be incurred as a result of improper selection. The design process has great flexibility for

change in minor items, but very little can be done in the detailed substation design to overcome

deficiencies in major equipment selection.

5.2 POWER TRANSFORMERS

5.2.1 General

The primary function of a power transformer is to transform system voltage from one nominal level to

another. The transformer has to be capable of carrying (within the guidelines of ANSI/IEEE Std.

C57.92) the power flow for its particular location in the system under various operating conditions and

contingencies, such as line or transformer outages.

This section deals primarily with oil-filled power transformers with nominal primary voltage ratings of

230 kV and below and utilizing one of the following methods of cooling:

1. Self-cooled (OA)

2. Self-cooled and assisted by forced-air (OA/FA for one stage; OA/FA/FA for two stages)

3. Self-cooled and assisted by forced-air and forced-oil (OA/FA/FOA or OA/FOA/FOA for two

stages)

Other methods of cooling such as with water are available and are described in IEEE Std. C57.12.00.

The type of cooling used is based on the requirements of the specifications, the size of the transformer,

and the manufacturer’s standard design.

Meeting these specific requirements usually results in the power transformer’s being the largest,

heaviest, and most costly piece of equipment used in a substation.

Because of their great importance and complexity, power transformers require special care in their

application, specification, and procurement. This is best accomplished by taking full advantage of

applicable industry standards and guides of national organizations such as the American National

Standards Institute (ANSI), Institute of Electrical and Electronic Engineers (IEEE), National Electrical
Bulletin 1724E-300

Page 192

Manufacturers Association (NEMA), etc., and RUS IP 202-1, “List of Materials Acceptable for Use on

Systems of RUS Electrification Borrowers.”

The following discussion highlights various aspects of power transformers and provides guidance and

recommendations to assist cooperatives in obtaining the proper equipment for their systems. Most of

this discussion will apply to step-down transformers, especially those not included in the List of

Materials. Refer to RUS Bulletin 50-91, “RUS Specification for Step-Down Distribution Substation

Transformers,” for step-down transformers.

5.2.2 Types

Power transformers may be either autotransformers or multiwinding conventional transformers. A

three-phase installation may consist of a three-phase unit or three single-phase units. The decision as to

what type of transformer to purchase depends on such factors as initial installed cost, maintenance

costs, operating cost (efficiency), reliability, etc. Three-phase units have lower construction and

maintenance costs and can be built to the same efficiency ratings as single-phase units. The initial cost

of a three-phase transformer is usually approximately one-third less than four single-phase units.

Additionally, the exposure of three-phase units to long outages can be minimized system-wide when a

mobile substation or transformer is available for backup in case of failure. RUS Bulletin 61-16, “Guide

for Economic Evaluation of Distribution Transformers,” provides information for evaluating substation

transformer costs.

The kVA ratings for various sizes of transformers are covered by the standards. IEEE Std. C57.12.00,

Table 1, defines the preferred continuous ratings for both single - and three-phase units. ANSI

Std. C57.12.10, Tables 2 and 12, further define the ratings of transformers with and without cooling.

Transformers 10,000 kVA and below can accommodate one stage of cooling only, while transformers

larger than 10,000 kVA can include up to two stages of cooling. Each stage of cooling increases the

capacity of the transformer by a fixed percentage of the base (OA) rating. For three-phase transformers

rated between 750 and 2000 kVA, increasing the base level of cooling to forced air cooling will

increase the continuous kVA capacity by 15 percent. For transformers rated 2500 kVA to 10,000 kVA,

the increase is 25 percent. For transformers above 10,000 kVA, additional stages of cooling may be

used to increase the continuous kVA rating of the transformer by 33 percent per stage. Transformers

larger than those listed in these tables can be purchased and would normally be triple rated or would

have provision for the future addition of two stages of cooling equipment to produce a triple rating.

The choice between conventional two- or three-winding transformers and autotransformers involves

their basic differences as they may affect the application and cost factors. In general, autotransformers

are considered primarily because of cost advantages where the voltage transformation ratio is favorable,

up to possibly 3/1. Beyond this ratio, the cost advantage of autotransformers diminishes. Also,

autotransformers are wye connected and thus provide only an in-phase angular relationship between

primary and secondary voltages.

Other advantages of autotransformers are smaller physical size, lighter weight, lower regulation

(voltage drop in transformer), smaller exciting currents (easier no-load switching), and lower losses.

The main disadvantages of autotransformers are lower reactance (impedance), more complex design

problems, and adverse affect on ground relaying. These problems can usually be resolved.
Bulletin 1724E-300

Page 193

5.2.3 Ratings

5.2.3.1 Capacity: The selection of substation transformer kVA capacity should be based on an

acceptable up-to-date engineering study. The selection should consider the effects of load cycle, load

factor, and ambient temperature as described in ANSI/IEEE Std. C57.92, “Guide for Loading Mineral

Oil-Immersed Power Transformers up to and Including 100 MVA With 55°C or 65°C Average

Winding Rise.”

Since cooling efficiency decreases with increase in altitude, the transformer manufacturer should be

informed when the transformer will be operated at an elevation above 1000 meters (3300 feet) so that

the proper cooling system can be provided. See Tables 5-1 and 5-2 for guidance on the effect of

altitude on temperature rise. Also, multiwinding transformers with loads on various windings at

different power factors have higher load losses and may require additional cooling capacity.

Table 5-1: Maximum Allowable Average Temperature* of Cooling Air for Carrying Rated kVA.

Ref. ANSI/IEEE Std. C57.92-1981, Table A1. Copyright © 1981. IEEE. All rights reserved.

Method of Cooling Apparatus 1000 Meters

(3300 Feet)

2000 Meters

(6600 Feet)

3000 Meters

(9900 Feet)

4000 Meters

(13 200 Feet)

Degrees Celsius

Liquid-Immersed Self-Cooled 30 28 25 23

Liquid-Immersed Forced-Air-Cooled 30 26 23 20

Liquid-Immersed Forced-Oil-Cooled

with Oil-to-Air Cooler

30 26 23 20

* It is recommended that the average temperature of the cooling air be calculated by averaging

24 consecutive hourly readings. When the outdoor air is the cooling medium, the average of the

maximum and minimum daily temperatures may be used. The value obtained in this manner is

usually slightly higher, by not more than 0.3oC, than the true daily average.

Table 5-2: Rated kVA Correction Factors for Altitudes Greater than 3300 ft (1000 m).

Ref. ANSI/IEEE Std. C57.92-1981, Appendix. Copyright © 1981. IEEE. All rights reserved.

Types of Cooling Derating Factor

(%)

Liquid-immersed air-cooled 0.4

Liquid-immersed water-cooled 0.0

Liquid-immersed forced-air-cooled 0.5

Liquid-immersed forced-liquid-cooled

with liquid-to-air cooler 0.5

Liquid-immersed forced-liquid-cooled

with liquid-to-water cooler 0.0

In addition to selecting a transformer capable of satisfying the basic capacity requirements, it is also

desirable to give due consideration to inventory and standardization with the objective of simplifying

spare parts, testing, maintenance, and unit sparing problems.

5.2.3.2 Temperatures: Normal transformer design is based on ambient temperatures of 40°C

maximum, 30°C average over 24 hours, and –20°C minimum. Abnormal ambient temperatures should
Bulletin 1724E-300

Page 194

be made known to the manufacturer at the time of purchase since they usually require modifications in

the design of the transformer.

5.2.3.3 Voltage: Nominal voltage ratings of a transformer are selected to conform to system

voltage conditions. Tables 5-3, 5-4, 5-5, and 5-6 list standard voltages through 230 kV. According to

ANSI/ IEEE Std. C57.12.10, transformers should not be subjected to operating voltages or volts per

hertz above 105 percent of any rated secondary tap when operating loaded to nameplate kVA rating

when the load power factor is 80 percent or higher and the frequency is at least 95 percent of rated

value. In addition, transformers should not be operated continuously above 110 percent of rated

secondary tap when operating at no-load. Multiwinding transformers and autotransformers may be

restricted further depending on the specific design criteria specified when the transformer was

purchased. Refer to the original specifications or the manufacturer for guidance. Also refer to ANSI

Std. C84.1 for further guidance on maximum permissible operating voltages.

Table 5-3: Range of Voltage and Kilovolt-Ampere Ratings for Single-Phase Transformers,

833-8333 kVA. Ref. ANSI/IEEE Std. C57.12.10-1988, Table 3. Reproduced with permission

of the National Electrical Manufacturers Association.

Low-Voltage Ratings (V)

6900/11 950Y, 14 400/24 940Y

2400/4160Y, 8355/23 085PW, 23 555W -

2520/4360Y, 7560/13 090Y, 12 600, 34 500,

4800/8320Y, 7620/13 200Y, 13 200, 19 920/34 500Y

- - 13 800 -

480 5040/8720Y 7970/13 800Y 14 400 20 920/36 230

High-Voltage

Ratings

(V) Self-Cooled (OA) Kilovolt-Ampere Ratings (kVA)

2400/4160Y 833 - - - -

4800/8320Y 833 - - - -

6900/11 950Y, 833, 1250 833-2500 - - -

6930/12 000Y, - - - - -

7200/12 470Y, - - - - -

7620/13 200Y, - - - - -

7970/13 800Y, - - - - -

12 000, 13 200, - - - - -

13 800 - - - - -

23 000 833, 1250 833-2500 833-2500 - -

34 500 833, 1250 833-2500 833-3333 833-3333 -

46 000 833, 1250 833-2500 833-8333 833-3333 -

69 000 - 833-2500 833-8333 833-3333 -

115 000 - 2500 2500-8333 2500-8333 2500-8333

138 000 - 2500 2500-8333 2500-8333 2500-8333

Notes:

(1) All voltages are Δ unless otherwise indicated.

(2) Kilovolt-ampere ratings separated by a dash indicate that all the intervening ratings listed in Table 1 are

included.

Kilovolt-ampere ratings separated by a comma indicate that only those listed are included.

(3) Bold-type voltages listed in ANSI Std. C84.1-1982.

(4) Italics-type voltages not listed in ANSI Std. C84.1-1982.
Bulletin 1724E-300

Page 195

Table 5-4: Range of Voltage and Kilovolt-Ampere Ratings for Three-Phase Transformers

Without Load Tap Changing, 750-10 000kVA. Ref ANSI/IEEE Std. C57.12.10-1988, Table 4.

Reproduced with permission of the National Electrical Manufacturers Association.

Low-Voltage Ratings (V)

24 940Grd/14 000

6900,7200,7560,

12 407Y/7200,

2400,2520 4800,5040, 13 090Y/7560, 13 800, 34 500,

480Y/277 4160Y/2400, 8320Y/4800, 13 200Y/7620 12 000,

12 600,

34 500GrdY/19 920,

480 4360Y/2520 8720Y/5040 13 800Y/7970, 13 200,

14 400

36 230GrdY/20 920

HighVoltage

Ratings

(V) Self-Cooled (OA) Kilovolt-Ampere Ratings (kVA)

2400 750-1500 - - - - -

4160,4800 750-1500 - - - - -

6900,7200 750-2500 1000-3750 - - - -

12 000 750-2500 1000-7500 - - - -

12 470 - - - - - -

13 200 - - - - - -

13 800 - - - - - -

23 000 - 1000-7500 1000-10 000 1000-10 000 - -

34 500 - 1000-7500 1000-10 000 1000-10 000 1000-10 000 -

46 000 - 1500-7500 1500-10 000 1500-10 000 1500-10 000 -

69 000 - 1500-7500 1500-10 000 1500-10 000 1500-10 000 -

115 000 - 5000-7500 5000-10 000 5000-10 000 5000-10 000 5000-10 000

138 000 - 5000-7500 5000-10 000 5000-10 000 5000-10 000 5000-10 000

Notes:

(1) All voltages are Δ unless otherwise indicated.

(2) Kilovolt-ampere ratings separated by a dash indicate that all the intervening ratings listed in Table 1 are

included.

(3) Bold-type voltages listed in ANSI Std. C84.1-1982.

(4) Italics-type voltages not listed in ANSI Std. C84.1-1982.
Bulletin 1724E-300

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Table 5-5: Range of Voltage and Kilovolt-Ampere Ratings for Three-Phase Transformers

with Load Tap Changing, 3750-10 000 kVA. Ref. ANSI/IEEE Std. C57.12.10-1988, Table 5.

Reproduced with permission of the National Electrical Manufacturers Association.

Low-Voltage Ratings (V)

24 940Grd/14 000

6900,7200,7560,

12 470Y/7200,

2400,2520, 4800,5040, 13 090Y/7560, 13 800 34 500,

4160Y/2400, 8320Y/4800, 13 200Y/7620, 12 000,12 600 34 500GrdY/19 920,

4360Y/2520 8720Y/5040 13 800Y/7970 13 200,14 400 24940Grd/

14000

36 230GrdY/20 920

HighVoltage

Ratings

(V) Self-Cooled (OA) Kilovolt-Ampere Ratings (kVA)

6900,7200 3750 - - - - -

12 000 3750-7500 - - - - -

12 470 - - - - - -

13 200 - - - - - -

13 800 - - - - - -

23 000 3750-7500 3750-10 000 3750-10 000 - - -

34 500 3750-7500 3750-10 000 3750-10 000 3750-10 000 - -

46 000 3750-7500 3750-10 000 3750-10 000 3750-10 000 - -

69 000 3750-7500 3750-10 000 3750-10 000 3750-10 000 - -

115 000 5000-7500 5000-10 000 5000-10 000 5000-10 000 5000-10 000 5000-10 000

138 000 5000-7500 5000-10 000 5000-10 000 5000-10 000 5000-10 000 5000-10 000

Notes:

(1) All voltages are Δ unless otherwise indicated.

(2) Kilovolt-ampere ratings separated by a dash indicate that all the intervening ratings listed in Table 1 are

included.

(3) Bold-type voltages listed in ANSI Std. C84.1-1982.

(4) Italics-type voltages not listed in ANSI Std. C84.1-1982.
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Table 5-6: Range of Voltage and Kilovolt-Ampere Ratings for Three-Phase Transformers

With or Without Load Tap Changing, 12 000-60 000 kVA. Ref. ANSI/IEEE Std. C57.12.10-1988,

Table 6. Reproduced with permission of the National Electrical Manufacturers Association.

High

Voltage

Ratings

(V)

Low-Voltage Ratings (V)

6900,7200,7560,

12 407Y/7200,

4800,5040, 13 090Y/7560, 12 000,12 600, 34 500,

8320Y/4800, 13 200Y/7620, 13 200, 13 800, 34 500GrdY/19 920,

8720Y/5040 13 800Y/7970 14 400 24 940GrdY/14 400 36 230GrdY/20 920

Self-Cooled (OA) Kilovolt-Ampere Ratings (kVA)

23 000 12 000-15 000 12 000-30 000 - - -

34 500 12 000-15 000 12 000-30 000 12 000-30 000 - -

46 000 12 000-15 000 12 000-30 000 12 000-30 000 - -

69 000 12 000-15 000 12 000-30 000 12 000-30 000 - -

115 000 12 000-15 000 12 000-60 000 12 000-60 000 12 000-60 000 12 000-60 000

138 000 12 000-15 000 12 000-60 000 12 000-60 000 12 000-60 000 12 000-60 000

161 000 12 000-15 000 12 000-60 000 12 000-60 000 12 000-60 000 12 000-60 000

230 000 12 000-15 000 12 000-60 000 12 000-60 000 12 000-60 000 12 000-60 000

Notes:

(1) All voltages are Δ unless otherwise indicated.

(2) Kilovolt-ampere ratings separated by a dash indicate that all the intervening ratings listed in Table 1 are

included.

(3) Bold-type voltages listed in ANSI Std. C84.1-1982.

(4) Italics-type voltages not listed in ANSI Std. C84.1-1982.

5.2.3.4 Basic Insulation Levels (BIL): Tables 5-7, 5-8, and 5-9 list basic insulation levels

commonly used for various system voltages. Neutral terminal BIL may be specified at a different level

than the line terminals depending on the type of system grounding being used. Table 5-10 lists the

minimum insulation levels for neutral terminals. Continuous improvements over the years in the

protective margins provided by surge arresters have enabled users to select reduced insulation levels for

transformers, at appreciable cost reductions, without sacrificing reliability.
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Table 5-7: Relationships of Nominal System Voltage to Maximum System Voltage and Basic

Lightning Impulse Insulation Levels (BIL) for Systems 765 kV and Below.

Ref. IEEE Std. C57.12.00-1993, Table 3. Copyright © 1993. IEEE. All rights reserved.

Application Nominal

System

Voltage

(kV rms)

Maximum System Voltage

(from ANSI C84.1-1989 [2]

and ANSI C92.2-1987 [4])

(kV rms)

Basic Lightning Impulse

Insulation Levels (BIL)

in Common Use

(kV crest)

Distribution 1.2 30

2.5 45

5.0 60

8.7 75

15.0 95

25.0 150 125

34.5 200 150 125

46.0 48.3 250 200

69.0 72.5 350 250

Power 1.2 45 30

2.5 60 45

5.0 75 60

8.7 95 75

15.0 110 95

25.0 150

34.5 200

46.0 48.3 250 200

69.0 72.5 350 250

115.0 121.0 550 450 350

138.0 145.0 650 550 450

161.0 169.0 750 650 550

230.0 242.0 900 825 750 650

345.0 362.0 1175 1050 900

500.0 550.0 1675 1550 1425 1300

765.0 800.0 2050 1925 1800

NOTES:

(1) BIL values in bold typeface are listed as standard in one or more of ANSI/IEEE Std. C57.12.10-1987 [B1],

ANSI/IEEE Std. C57.12.20-1988 [B3], ANSI/IEEE Std. C57.12.21-1980 [B4], ANSI/IEEE Std. C57.12.22-

1989 [B5], ANSI/IEEE Std. C57.12.23-1986 [B6], ANSI/IEEE Std. C57.12.24-1988 [B7], ANSI/IEEE

Std. C57.12.25-1990 [B8], and ANSI/IEEE Std. C57.12.26-1992 [B13].

(2) Single-phase distribution and power transformers and regulating transformers for voltage ratings between

terminals of 8.7 kV and below are designed for both Y and Ä connection, and are insulated for the test

voltages corresponding to the Y connection so that a single line of transformers serves for the Y and Ä

applications. The test voltages for such transformers, when operated and connected, are therefore higher

than needed for their voltage rating.

(3) For series windings in transformers, such as regulating transformers, the test values to ground shall be

determined by the BIL of the series windings rather than by the rated voltage between terminals.

(4) Values listed as nominal system voltage in some cases (particularly voltages 34.5 kV and below) are

applicable to other lesser voltages of approximately the same value. For example, 15 kV encompasses

nominal system voltages of 14 440 kV, 13 800 kV, 13 200 kV, 13 090 kV, 12 600 kV, 12 470 kV,

12 000 kV, 11 950 kV, etc.
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Table 5-8: High-Voltage Winding Insulation Levels of Single-Phase Transformers.

Ref. ANSI/IEEE Std. C57.12.10-1988, Table 7.

Reproduced with permission of the National Electrical Manufacturers Association.

High-Voltage Ratings

(V)

Basic Impulse

Insulation Level

(kV)

2400/4160Y 75

4800/8320Y 95

6900/11 950Y 110

7200/12 470Y 110

7620/13 200Y 110

12 000 110

13 200 110

13 800 110

23 000 150

34 500 200

46 000 250

69 000 350

115 000 450

138 000 550

Notes:

(1) All voltages are Δ unless otherwise indicated.

(2) Bold type are voltages listed in ANSI C84.1-1982.

(3) Italics type are voltages not listed in ANSI C84.1-1982.

Table 5-9: High-Voltage Winding Insulation Levels of Three-Phase Transformers.

Ref. ANSI/IEEE Std. C57.12.10-1988, Table 8.

Reproduced with permission of the National Electrical Manufacturers Association.

Basic Impulse Insulation Level (kV)

High-Voltage Ratings

(V)

Distribution

Transformers

Power

Transformers

2 400 45 60

4 160 60 75

4 800 60 75

6 900 75 95

7 200 75 95

12 000 95 110

13 200 95 110

13 800 95 110

23 000 125 150

34 500 150 200

46 000 - 250

69 000 - 350

115 000 - 450

138 000 - 550

161 000 - 650

230 000 - 750

Notes:

(1) All voltages are Δ unless otherwise indicated.

(2) Distribution BILs only applicable to non-load-tap-changing transformers.
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Table 5-10: Minimum Insulation Levels at Neutral.

Ref. ANSI/IEEE Std. C57.12.00-1993, Table 7. Copyright © 1993. IEEE. All rights reserved.

Minimum Low-Frequency

Insulation Level (kV rms)

Application

Nominal

System

Voltage

(kV)*

Grounded Solidly or

Through a Current

Transformer or

Through a

Regulating Transformer

Grounded Through

a Ground-Fault

Neutralizer, or

Isolated but

Impulse Protected

Column 1 Column 2 Column3

1.2 10 10

2.6 15 15

5.0 19 19

8.7 26 26

15.0 26 26

25.0 26 34

34.5 26 50

46.0 34 70

Distribution

or

Power

69.0 34 95

* For higher line terminal system voltages than shown above, the insulation level at the neutral

shall be specified to conform with service requirements, but in no case shall be less than 34 kV.

NOTE: When specified, Y-Y connected transformers using a common, solidly grounded neutral may

use a neutral bushing selected in accordance with the requirements of the LV winding.

Any selection of a transformer with reduced BIL is a user responsibility and requires knowledge of

certain system characteristics.

On effectively grounded systems, a reduced BIL of one step below full basic insulation level may be

appropriate for transformers with nominal ratings of 115 kV and above. An insulation coordination

study may be required to ensure that adequate margin is maintained between transformer insulation

strength and the protective level of protective equipment.

5.2.3.5 Loading: A transformer can supply a load beyond its nameplate rating for various periods

of time, which may or may not affect its normal life, depending on several factors related to

temperature conditions in the transformer. See ANSI/IEEE Std. C57.92 for additional guidance on

transformer loading.

5.2.4 Taps

No-load tap changers (NLTC) and/or load tap changers (LTC) can be obtained on power transformers.

The addition of no-load taps in the primary of a substation transformer makes it possible to adapt the

transformer to a range of supply voltages (usually a 10 percent overall range of which 5 percent is

above nominal and 5 percent below nominal, usually in 2.5 percent steps). Since no-load taps are not

capable of interrupting any current including transformer charging current, the transformers have to be

de-energized when the manual no-load tap position is changed. All taps should have full capacity

ratings. The individual tap voltages should be as specified in ANSI/IEEE Std. C57.12.10, paragraph

4.5.

Any decision to use load tap changing transformers should be based on a careful analysis of the

particular voltage requirements of the loads served and consideration of the advantages and
Bulletin 1724E-300

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disadvantages, including costs, of alternatives such as separate voltage regulators. When load tap

changing transformers are specified, they have to comply with the requirements of ANSI/IEEE

Std. C57.12.00, and ANSI/IEEE Std. C57.12.10.

5.2.5 Impedance

Transformer impedance affects transformer voltage regulation, efficiency, and magnitude of throughshort-circuit currents. Both regulation and efficiency are generally improved with lower impedance.

However, these desirable results should be viewed along with higher through-fault currents permissible

with lower impedance.

Higher load-side fault currents can be potentially damaging to the transformer and may also require

higher fault current ratings of load-side equipment at increased cost. Prudent compromises are thus

often required in specifying transformer impedance.

Where through-fault currents are not a significant factor, it is generally desirable to specify as low

impedance as possible that will not result in increased transformer cost. Standard impedance ranges for

various transformer BIL ratings are listed by manufacturers, and cost penalties may apply when the

impedance falls above or below these ranges. The standards permit manufacturing tolerances of

±7.5 percent of the specified impedance for two-winding transformers and ±10.0 percent for

multiwinding transformers and autotransformers. These are important to remember if transformer

paralleling is being considered and if the margin between transformer through-fault current and

equipment ratings is very close. Substation transformer impedance needs to comply with the

requirements of ANSI/IEEE Std. C57.12.10, Section 6. Standard impedances for various voltage

ratings are given in Table 5-11. Distribution substation transformers (500 kVA or smaller) should be

specified with standard impedance where possible. These impedances are sufficient to make the

transformer self protecting under any secondary faults.

5.2.6 Phase Relation

Proper phase relationships between the various winding voltages are extremely important in transformer

application. These have to be selected to fit existing or planned conditions in the particular system.

Standard single-phase substation transformers are built with subtractive polarity. The polarity of a

three-phase transformer is fixed by its connections between phases and by relative location of leads. A

standard delta-wye or wye-delta, three-phase, step-down transformer will result in the high-side

voltages leading their respective low-side voltages by 30 degrees. An installation of three single-phase

transformers can be connected to accomplish this same relationship.

Autotransformers are connected wye-wye, and no phase angle exists between the high- and low-side

voltages. This may preclude the use of autotransformers, in some cases, even when they are otherwise

preferred. See Section 5.2.7 concerning the phase relationship required for parallel operation of

transformers.

Also give attention to the proper physical orientation of transformers within the substation and to their

connections to ensure that the proper phasing is obtained on all buses. Standard bushing arrangement

on a three-phase transformer, when viewed from the low-voltage side, is from left to right H0 (when

required), Hl, H2, and H3 on the high-voltage side and X0 (when required), X1, X2, and X3 on the lowvoltage side. If a tertiary or third winding is provided, the bushing arrangement is Y1, Y2, and Y3 left to

right when viewed from the side nearest these bushings.
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Table 5-11: BILs and Percentage Impedance Voltages at Self-Cooled (OA) Rating.

Ref. ANSI/IEEE Std. C57.12.10-1988, Table 10 and Section 4.6.

Reproduced with permission of the National Electrical Manufacturers Association.

Without Load Tap

Changing

With Load Tap

Changing

High-Voltage BIL

(kV)

Low

Voltage

480 V

Low

Voltage

2400 V

and

Above

Low Voltage

2400 V and Above

60-110 5.75* 5.5* —

150 6.75 6.5 7.0

200 7.25 7.0 7.5

250 7.75 7.5 8.0

350 — 8.0 8.5

450 — 8.5 9.0

550 — 9.0 9.5

650 — 9.5 10.0

750 — 10.0 10.5

* For transformers greater than 5000 kVA self-cooled, these values shall be the same as those

shown for 150 kV HV BIL.

1. Impedance Voltage:

a. Percentage Impedance Voltage: the percentage impedance voltage at the self-cooled rating as

measured on the rated voltage connection shall be as listed in Table 5.2-10.

b. Tolerance on Impedance Voltage: the tolerance shall be as specified in ANSI/IEEE

Std. C57.12.00-1993.

c. Percentage Departure of Impedance Voltage on Taps for De-energized Operation: the

percentage departure of tested impedance voltage on any tap from the tested impedance

voltage at rated voltage shall not be greater than the total tap voltage range expressed as a

percentage of the rated voltage.

Note: This does not apply to load-tap-changing taps.

Refer to ANSI/IEEE Std. C57.12.70 for transformer terminal markings and connections.

5.2.7 Parallel Operation of Transformers

In most cases, the purchase of two smaller size transformers, to be operated in parallel in one circuit, in

lieu of one full-size transformer, is not recommended. Two transformers will cost more than a single

transformer of equivalent capacity, their combined losses are higher, and they require a more elaborate

and expensive substation structure to accommodate them. However, where a situation exists for

possible parallel operation, such as where continuity of at least partial service in event of failure of one

unit is of great importance, the transformers should be individually protected and the following

guidelines considered.

Any two or more transformers can be operated in parallel, provided their impedances are in the same

order of magnitude when considered on their own kVA base, their voltage taps and voltage ratios are

essentially the same, and their polarity and phase voltage displacement are or can be made alike.

Equal impedances will permit proportionate sharing of the load between transformers. If not equal, the

load will be divided in inverse proportion to the magnitude of the impedance. This condition is
Bulletin 1724E-300

Page 203

satisfactory within reasonable limits, as determined by requirements, and may be of little consequence

where the larger of two transformers has the lower impedance and will carry more than its proportionate

share of the load. However, if the smaller unit has the lower impedance, it will carry more than its

share of the load and may even become severely overloaded, while the larger unit still has available

capacity. This is demonstrated in the following example.

Protecting transformers operating in parallel as a single unit is not recommended. The sensitivity of the

high-side protection is significantly reduced, and the occurrence of nuisance tripping during

energization is increased due to incorrect differential relay harmonic restraint unit operation.

5.2.7.1 Condition I - Larger Transformer Has the Smaller Impedance: Two transformers, Tl

and T2, are operating in parallel. Tl is rated 10 MVA with an impedance of 10 percent. T2 is rated 25

MVA with an impedance of 7 percent. On a common 100 MVA base, impedance of Tl is 100 percent

and impedance of T2 is 28 percent.

Power flow divides inversely with the relative impedances on a common base. Assuming a total power

flow of 30 MVA, Tl would carry 6.6 MVA and T2 would carry 23.4 MVA, both within their ratings.

The power flow distribution is obtained by solving two simultaneous equations, where Pl and P2

represent the power flows through Tl and T2, respectively, and Z100 is the impedance on a 100 MVA

base:

Equation 5-1

Pl + P2 = 30 MVA

Equation 5-2

P

P

Z of T

Z of T

1

2

2

1

100

100

=

( )

( )

5.2.7.2 Condition II - Smaller Transformer Has the Smaller Impedance: The same as

Condition I, except Tl has an impedance of 7 percent, and T2 an impedance of 10 percent. On a

100 MVA base, the impedance of Tl is 70 percent and the impedance of T2 is 40 percent.

Tl would carry 10.9 MVA and T2 would carry 10.1 MVA. Tl is clearly overloaded, whereas T2 has

capacity to spare.

5.2.7.3 Condition III - Both Transformers Have Equal Impedances - Preferred Condition:

The same as Condition I, except both TI and T2 have equal impedances on their own base of 8 percent.

On a 100 MVA base, Tl has an impedance of 80 percent, and T2 has an impedance of 32 percent. TI

would carry 8.6 MVA and T2 would carry 21.4 MVA. Each transformer is carrying its correct share in

proportion to its MVA rating.

From an impedance standpoint, it has generally been accepted that transformers can be paralleled

successfully if the actual or nameplate impedance of one does not differ by more than 7 1⁄2 percent from

the actual or nameplate impedance of the other. For example, a transformer having an impedance of
Bulletin 1724E-300

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6 percent can be paired with a transformer having an impedance anywhere between 5.55 percent (0.925

x 6 percent) and 6.45 percent (1.075 x 6 percent).

Equal tap voltages, or voltage ratios, will permit each of the paralleled transformers to operate as if it

were isolated. But unequal tap voltages will create a circulating current flowing forward through the

unit having the higher voltage and in a reverse or leading direction through the unit with the lower

voltage. This condition is limited only by the series impedance of the two transformers in the current

circulation circuit and by the difference in voltage causing the current flow. This condition can be very

severe and has to be closely analyzed whenever such operation is contemplated. The condition is most

severe when the transformers are not carrying load. It usually is modified sufficiently when load is

being carried, and voltage regulation due to load so modifies the voltage difference as to reduce the

circulating current to an insignificant level.

Where paralleled transformers are equipped with load tap changers and line drop compensators,

incorporate paralleling control schemes into the LTC controls. Schemes that may be evaluated include:

1. Negative Reactance Method

2. Step-by-Step Method

3. Out-of-Step Switch Method

4. Cross-Current Compensation Method

5.2.8 Dielectric Requirements

A transformer in service may be exposed to a variety of dielectric stresses. Lightning impulses may

reach the terminals of the transformer because of direct hits or, more likely, in the form of traveling

waves coming in over connecting lines. Such traveling waves are produced when the connecting lines

are exposed to lightning strokes.

Direct hits are practically impossible where adequate direct stroke protection is provided over the

substation in the form of ground wires and/or masts. The magnitude of traveling wave impulses

reaching the transformer depends on:

• The initial magnitude of the strokes

• The distance the wave has to travel

• Transmission line characteristics, such as surge impedance, insulation level, and type of

ground wire protection

• Transformer characteristics and protective characteristics of surge protective devices

provided

How well the transformer can withstand any impulse voltages reaching it depends on the condition of

the insulation at the time of the impulse. Basic insulation levels can be verified by impulse tests. Most

large transformers receive impulse tests prior to shipment from the factory. This may not be a routine

test performed by the manufacturer for certain size transformers. If an impulse test is desired, include

this requirement in the testing section of the transformer specifications.

Normal line energization and deenergization or power circuit breaker operations during system faults

produce switching surges that travel down the conductors to the connected transformers. Switching

surges generally present no particular problem to transformers rated 230 kV and below. Transformers

rated 115 kV and above are designed for the switching impulse insulation levels (BSL) associated with

their assigned BIL. Switching impulse insulation levels are defined in Tables 5-12 and 5-13. In
Bulletin 1724E-300

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general, switching surge withstand capability of a transformer is approximately 83 percent of its BIL.

Where justified, factory switching surge tests may be applied to verify switching surge withstand

capability.

Table 5-12: Dielectric Insulation Levels for Distribution Transformers

and Class I Power Transformers.* Ref. IEEE Std. C57.12.00-1993, Table 4.

Copyright © 1993. IEEE. All rights reserved.

Chopped-Wave Impulse

Levels

Front-of-Wave Impulse

Levels

Application

Basic

Lightning

Impulse

Insulation

Level (BIL)

(kV crest)

Minimum

Voltage

(kV crest)

Minimum

Time to

Flashover

(μs)

Minimum

Voltage

(kV crest)

Specific

Time

to Sparkover

(μs)

LowFrequency

Test Level

(kV rms)

Column 1 Column 2 Column 3 Column 4 Column 5 Column 6

Distribution 30 36 1.0 — — 10

 45 54 1.5 — — 15

 60 69 1.5 — — 19

 75 88 1.6 — — 26

 95 110 1.8 — — 34

125 145 2.25 — — 40

150 175 3.0 — — 50

200 230 3.0 — — 70

250 290 3.0 — — 95

350 400 3.0 — — 140

Power 45 50 1.5 — — 10

 60 66 1.5 — — 15

 75 83 1.5 — — 19

 95 105 1.8 165 0.5 26

110 120 2.0 195 0.5 34

150 165 3.0 260 0.5 50

200 220 3.0 345 0.5 70

250 275 3.0 435 0.5 95

350 385 3.0 580 0.58 140

* See Section 5.10 for a description of Class I power transformers.

NOTES:

(1) Front-of-wave impulse levels have to be specified prior to design of the trans former.

(2) Front-of-wave tests are not recommended on low-voltage or tertiary windings that will not

be exposed to lightning and that are connected directly to user equipment and have low

impulse strengths. This includes low-voltage windings of generator transformers and

transformer windings that operate at 5000 V or less.

(3) Internal and external phase-to-phase low-frequency insulation test levels shall not be

reduced below the levels listed in Table 6.

(4) The insulation levels for distribution transformers and for Class I power transformers shall

be selected from this table for both the high-voltage and the low-voltage windings.

(5) The BIL serves both as a test level for the full-wave lightning impulse tests and as the

primary identity of a set of coordinated insulation levels.
Bulletin 1724E-300

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Table 5-13: Dielectric Insulation for Class II Power Transformers.*

Ref. IEEE Std. C57.12.00-1993, Table 5. Copyright © 1993. IEEE. All rights reserved.

Induced-Voltage Test

(Phase-to-Ground)

Nominal

System

Voltage

(kV)

Basic

Lightning

Impulse

Insulation

Level (BIL)

(kV crest)

ChoppedWave Level

(kV crest)

Switching

Impulse

Level (BSL)

(kV crest)

One-Hour

Level

(kV rms)

Enhancement

Level

(kV rms)

Applied

Voltage

Test Level

(kV rms)

Column 1 Column2 Column 3 Column 4 Column 5 Column 6 Column 7

15 and below 110 120 — — 34

25 150 165 — — — 50

34.5 200 220 — — — 70

46 250 275 — — 95

69 250 275 — — — 95

115 350 385 280 105 120 140

450 495 375 105 120 185

550 605 460 105 120 230

138 450 495 375 125 145 185

550 605 460 125 145 230

650 715 540 125 145 275

161 550 605 460 145 170 230

650 715 540 145 170 275

750 825 620 145 170 325

230 650 715 540 210 240 275

750 825 620 210 240 325

825 905 685 210 240 275

900 990 745 210 240 395

345 900 990 745 315 360 395

1050 1155 870 315 360 460

1175 1290 975 315 360 520

500 1300 1430 1080 475 550 —

1425 1570 1180 475 550 —

1550 1705 1290 475 550 —

1675 1845 1390 475 550 —

765 1800 1980 1500 690 800 —

1925 2120 1600 690 800 —

2050 2255 1700 690 800 —

* See Section 5.10 for a description of Class II power transformers.

NOTES:

(1) For chopped-wave tests, the minimum time to flashover shall be 3.0 μs except for 110 kV

BIL, in which case the minimum time to flashover shall be 2.0 μs.

(2) Although Column 4 established phase-to-ground switching impulse levels, it is not always

possible to test these levels on low-voltage windings.

(3) Columns 5 and 6 provide phase-to-ground test levels that would normally be applicable

to wye windings. When the test voltage level is to be measured phase-to-phase, as is

normally the case with delta windings, then the levels in Column 5 have to be multiplied

by 1.732 to obtain the required phase-to-phase induced-voltage test level.

(4) The applied-voltage test is not applicable to wye-winding line terminals unless they have

been specified to be suitable for application on ungrounded systems.

(5) The insulation levels for Class II power transformers shall be selected from this table for

both the high-voltage and the low-voltage windings.

Properly applied surge arresters are very effective in limiting the magnitude of both impulse and

switching surge voltages reaching the transformer to levels below their withstand capabilities. Reduced

transformer BIL levels are often possible, at appreciable cost reduction, while still maintaining adequate

protective margins. Section 5.8 on surge arresters contains additional information on the subject.
Bulletin 1724E-300

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Transformers may be exposed to abnormal power frequency voltages during system fault conditions.

Single-phase-to-ground faults produce abnormal voltages to ground on the unfaulted phases. The

amount that these voltages increase above normal depends on how solidly the system is grounded.

With adequate BILs and surge arrester ratings, these temporary abnormal voltages should present no

difficulty for the transformer.

External porcelain insulation on a transformer is designed to withstand voltages to which it may be

subjected under varied atmospheric conditions. Severe atmospheric contamination may require

increased bushing BILs, increased porcelain creep distances, special porcelain treatment, or washing

procedures. Local experience under similar conditions is usually the best guide as to the most practical

solution.

Standard transformer external insulation is based on applications below 1,000 meters (3300 feet).

Above 1,000 meters, the lower air density offers less voltage withstand capability, and the external

insulation level has to be derated. Normal ratings are decreased approximately 10 percent for each

1,000-meter increase in elevation above 1,000 meters. See Table 5-1 and ANSI Std. C76.1, “Outdoor

Apparatus Bushings,” Table 3.2.1(c), for standard derating factors. Choose equipment of a suitably

higher rating if derating at high altitude is to be avoided.

5.2.9 Short Circuit Requirements

Failures of substation transformers because of through-fault currents have been a matter of great

concern to the industry for many years. The use of larger transformers and the increases in system fault

current contributed to the cause of failures. Transformer manufacturers and industry standards began to

address the issue of transformer through-fault capabilities in more detail. The standards were expanded

along with extensive testing to determine an accurate model of both the thermal and mechanical

withstand capabilities of transformers of various sizes. Cooperatives and their engineers should be

aware of this problem and should take appropriate measures to safeguard their interests in purchases of

power transformers.

5.2.9.1 Background Information: The current edition of ANSI/IEEE Std. C57.12 defines the

requirements for transformers of various sizes with respect to short-circuit withstand capabilities during

any type of external fault. In addition, ANSI/IEEE Std. C57.109 further defines the transformer

capabilities in terms of current versus time characteristics to allow proper coordination with transformer

overcurrent protection. ANSI/IEEE Std. C57.12.90 now includes an entire section on short-circuit

testing of transformers.

In brief, the standard requires the application of six short circuits at maximum current, two of which

would result in maximum asymmetry of the fault current based on the reactance to resistance (x/r) ratio

to the point of the fault as defined in ANSI/IEEE Std. C57.12.00, Section 7. The transformer should

show no damage after this test as indicated by measurements and visual inspections. For a complete

description of the test, refer to ANSI/IEEE Std. C57.12.90, “Standard Test Code for Liquid-Immersed

Distribution, Power, and Regulating Transformers and Guide for Short Circuit Testing of Distribution

and Power Transformers.”

The user has to still decide whether to require this test in the purchase specifications. Manufacturers’

facilities or test laboratories may be limited in terms of the size of transformer that can be short-circuit

tested. Larger sizes conceivably could be tested in the field by the purchaser, but the feasibility of

doing so on an operating system is questionable. The laboratory test is fairly costly, and shipping costs
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to and from the laboratory test facility should be added. The extra shipping and handling would also

subject the transformer to a greater risk of transportation shock damage and human error.

5.2.9.2 Recommendations: Single-phase transformers 10,000 kVA (OA) and smaller, rated

138 kV and below, and three-phase transformers 30,000 kVA (OA) and smaller, rated 138 kV and

below, are included in RUS IP 202-1. Cooperatives need not require short-circuit tests for transformers

in this category. RUS will either request manufacturers to conduct short-circuit tests on any new

transformer design proposed for listing or will request evidence that the transformer design has had a

history of successful experience in service. The cooperative should not specify unusual taps or

impedance in the purchase specification unless absolutely necessary. Such requirements may cause

design changes that will affect mechanical strength and introduce uncertainties in the ability of the

transformer to withstand short-circuit currents.

Specifications for transformers not included in the List of Materials* should include requirements for

short-circuit strength. The manufacturer should be required to demonstrate this strength either directly

through previous short-circuit testing of a similar unit or indirectly through a history of successful field

experience.

It should be recognized that short-circuit testing will not be feasible on the larger sizes of transformers

because of the limitations of existing laboratory facilities. Hence, successful experience will be the

principal means for measuring the adequacy of short-circuit strength of these transformers. In this

respect, it is recommended that experience be accepted as a demonstration that the transformer design

has adequate short-circuit strength. This applies only when transformers with core and coils identical in

all respects to the transformer covered by the specifications have amassed a total of at least 20

transformer years of experience without major failure attributable to design defects.

Where the manufacturer has not built units identical to the transformer covered by the specification, or

the experience record is less than 20 transformer years, it is recommended that short-circuit testing be

required by the specifications or a different manufacturer be selected.

5.2.9.3 Recommended Specification for Short-Circuit Strength: It is recommended that the

following be incorporated in all purchase specifications for power transformers not included in the List

of Materials:

“Without limiting in any way any obligation of the Bidder under this agreement, the Bidder

shall demonstrate to the satisfaction of the Owner that the transformer proposed to be

furnished under this specification shall have sufficient mechanical strength to withstand

without failure all through-fault currents. The Bidder shall demonstrate that the transformers

meet this requirement by one of the following methods:

1. Certified test data showing that a transformer with a core and coil identical in design and

construction and identical or similar with respect to kVA capacity, kV ratings, BIL,

 

*

 Transformers not included in RUS IP 202-1, List of Materials:

1. All substation power autotransformers

2. All transformers having three or more windings

3. Single-phase transformers rated greater than 10,000 kVA (OA) or 138 kV
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impedance, and voltage taps has been tested under maximum short-circuit conditions

without failure. A description of the test code under which the transformer was tested for

short-circuit strength will be provided by the Bidder to the Owner.

2. A history of successful experience with transformers of identical or similar ratings, design,

and construction. The Bidder shall list all transformers in service with core and coils that

are essentially identical in design, construction, and manufacture to the transformer covered

by this specification and shall provide information on the date of installation, location, and

failures, if any. Where such transformers have not been built or the cumulative service

record is less than 20 transformer years, a list of transformers in service that represent the

closest approximation to the transformer covered by this specification shall be submitted.

The information submitted shall be representative of the total experience of the manufacturer

with similar design to the transformer to be furnished. Information submitted shall include

the dates of installation (or shipment, if not installed), the ratings of the transformers, and a

list of failures and causes of failures if any have been experienced.”

Autotransformers or conventional multiwinding transformers often have special application and design

requirements. In such cases, it will be important to provide system short-circuit information indicating

the most severe short-circuit condition that can exist at the terminals of each transformer winding, and

any specific impedance requirements.

5.2.10 Cooling Equipment

Most of the smaller substation power transformers on rural systems are the oil-immersed, self-cooled

(OA) type. In these types of transformers, the oil transfers the heat from the core and coils to the tank

wall or cooling tubes, where it passes to the surrounding air. Temperature differences in the oil cause

the oil to circulate by convection through the tubes. Adequate airflow is essential to satisfactory

operation.

On larger transformers, this cooling process can be accelerated by various methods: using forced air

(FA) from fans over the cooling tubes, by using oil pumps to circulate the oil, or by a combination of

forced air and forced oil. Both methods can be automatically controlled in one or two steps from either

top oil temperatures or winding temperature or both. Forced cooling methods are usually effective in

reducing costs of the larger transformer sizes.

Where any type of forced cooling is relied on, it is essential that attention be given to adequate

operational reliability of the pumps and fans. This involves consideration of redundancy in the power

supply to the pumps and fans and to individual or group overload protection and disconnecting means.

Also, hot spot and top oil temperature devices can be used to alarm for abnormal cooling indications.

The temperature limits should be specified to adequately protect the unit but not to limit its overload

capability. Suggested alarm limits are listed in Table 5-14:

Table 5-14: Alarm Limits for Transformer Cooling

55°C 65°C

Insulation Insulation

Hottest Spot Temperature 95°C 105°C

Top Oil Temperature 70°C 80°C
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The cooling tubes or heat exchangers on large transformers should be specified for easy removal or

isolation from the transformer for repairs. In this case, shutoff valves and bolted flanges are provided at

the inlet and outlet of each heat exchanger. Transformers below a range of 10,000 kVA, three-phase,

and 5,000 kVA, single-phase, usually have nonremovable cooling tubes. These kVA sizes will vary

between manufacturers.

5.2.11 Oil and Oil Preservation Equipment

Transformer oil has to be kept free from contact with outside contaminants always present in the

atmosphere. On smaller substation transformers, the tank is completely sealed, with a layer of dry air or

nitrogen left above the oil to accommodate expansion and contraction of the oil.

Several methods of oil preservation (see Figure 5-1) are commonly used on larger size transformers:

1. A sealed tank with a positive pressure inert gas layer maintained above the oil by means of a

permanently connected tank of nitrogen gas

2. A tank completely filled with oil but connected to a raised tank or oil conservator, which

maintains a positive oil pressure in the main tank and provides a place for expansion and

contraction of the oil

3. A conservator tank with a divided expansion tank with two sections and the flexible diaphragm

conservator tank

4. A conservator tank with a bladder within the conservator tank as a variation of the flexible

diaphragm

The choice of oil preservation system is mostly a matter of personal preference and experience. All

have been successfully used for many years. Regardless of the method used, periodic tests have to be

made of the oil and oil preservation system to ensure that oil quality is being maintained.

5.2.12 Audible Sound

Sound (noise) levels produced by transformers, as well as other substation equipment, are becoming a

matter of increasing concern to the public. The fact that rural substations are more often located away

from congested areas reduces the possibility of complaints. However, this is partially offset by the

lower ambient sound levels common in rural areas.

In some areas, noise ordinances may dictate what is required. The designer should accordingly be

familiar with the problems and their solutions. A thorough treatment of the subject is beyond the scope

of this bulletin, but some practical guidelines follow. Any values given should be treated as

approximations.

5.2.12.1 Site: Sound is usually transmitted radially from the source. Avoid sites that have a direct

line of sight to possible areas of complaints. A particularly poor selection would be a low-level site

with residential areas on the surrounding higher ground.

5.2.12.2 Landscape : Natural or artificial barriers such as mounds or shrubbery positioned between

the sound source and the public are desirable. Although these have little effect on sound levels, they

can reduce the psychological impact of a new substation and prevent complaints.
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Figure 5-1: Methods of Oil Preservation
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5.2.12.3 Distance: Sound levels are attenuated with distance. Approximately a 6-dBA reduction

can be obtained with each doubling of the distance between source and point of measurement.

5.2.12.4 Sound Levels: Standard sound levels for transformers are listed in NEMA Std. TR1. See

Tables 5-15 (see page 213 of this bulletin), 5-16, and 5-17. Reduced sound level transformers may

increase the transformer cost approximately 1 1⁄2 percent for each dBA reduction from these NEMA

standard levels. Actual price variations for different sound levels can only be determined in a bid

process when all other design factors are considered. Transformer sound levels tend to increase with

BIL, kVA, and the number of stages of cooling. A practical limit in designing special low-sound-level

transformers is approximately a 12-dBA reduction where forced cooling is required. Greater reductions

require expensive measures, such as double-wall tanks.

Table 5-16: Audible Sound Levels for Liquid-Immersed Distribution Transformers

and Network Transformers. Ref. NEMA TR1-1993, Table 0-3.

Reproduced with permission of the National Electrical Manufacturers Association.

Equivalent

Two-Winding kVA

Average Sound Level,

Decibels

0-50 48

51-100 51

101-300 55

301-500 56

750 57

1000 58

1500 60

2000 61

2500 62

Table 5-17: Audible Sound Levels for Dry-Type Transformers, 15 000-Volt

Nominal System Voltage and Below. Ref. NEMA TR1-1993, Table 0-4.

Reproduced with permission of the National Electrical Manufacturers Association.

Equivalent Average Sound Level, Decibels

Two-Winding

kVA Self-Cooled

Ventilated*

Self-Cooled

Sealed*

Equivalent

Two-Winding

kVA

Average Sound

Level, Decibels

Ventilated

Forced Air

Cooled**, †

0-50 50 50 — —

51-150 55 55 — —

151-300 58 57 3-300 67

301-500 60 59 301-500 67

501-700 62 61 501-833 67

701-1000 64 63 834-1167 67

1001-1500 65 64 1168-1667 68

1501-2000 66 65 1668-2000 69

2001-3000 68 66 2001-3333 71

3001-4000 70 68 3334-5000 73

4001-5000 71 69 5001-6667 74

5001-6000 72 70 6668-8333 75

6001-7500 73 71 8334-10000 76

* Class AA rating.

** Does not apply to sealed-type transformers.

† Class FA and AFA ratings.
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Table 5-15: Audible Sound Levels for Oil-Immersed Power Transformers. REF. NEMA TR1-1993, Table 0-2.

Reproduced with permission of the National Electrical Manufacturers Association.

Column 1 – Class* OA, Ow, and FOW Ratings

Column 2 – Class* FA and FOA First-Stage Auxiliary Cooling**†

Column 3 – Straight FOA* Ratings, FA* FOA* Second-Stage Auxiliary Cooling*†

Equivalent Two-Winding Rating

350 kV BIL and Below 450, 550, 650 kV BIL 750 and 825 kV BIL 900 and 1050 kV BIL 1175 kV BIL 1300 kV BIL and Above

Average

Sound

Level ††

Decibels

1 2 3 1 2 3 1 2 3 1 2 3 1 2 3 1 2 3

57 700 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

58 1000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

59 -- -- -- 700 -- -- -- -- -- -- -- -- -- -- -- -- -- --

60 1500 -- -- 1000 -- -- -- -- -- -- -- -- -- -- -- -- -- --

61 2000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- --

62 2500 -- -- 1500 -- -- -- -- -- -- -- -- -- -- -- -- -- --

63 3000 -- -- 2000 -- -- -- -- -- -- -- -- -- -- -- -- -- --

64 4000 -- -- 2500 -- -- -- -- -- -- -- -- -- -- -- -- -- --

65 5000 -- -- 3000 -- -- -- -- -- -- -- -- -- -- -- -- -- --

66 6000 -- -- 4000 -- -- 3000 -- -- -- -- -- -- -- -- -- -- --

67 7500 6250 -- 5000 3750 -- 4000 3125 -- -- -- -- -- -- -- -- -- --

68 10000 7500 -- 6000 5000 -- 5000 3750 -- -- -- -- -- -- -- -- -- --

69 12500 9375 -- 7500 6250 -- 6000 5000 -- -- -- -- -- -- -- -- -- --

70 15000 12500 -- 10000 7500 -- 7500 6250 -- -- -- -- -- -- -- -- -- --

71 20000 16667 -- 12500 9375 -- 10000 7500 -- -- -- -- -- -- -- -- -- --

72 25000 20000 20800 15000 12500 -- 12500 9375 -- -- -- -- -- -- -- -- -- --

73 30000 26667 25000 20000 16667 -- 15000 12500 -- 12500 -- -- -- -- -- -- -- --

74 40000 33333 33333 25000 20000 20800 20000 16667 -- 15000 -- -- 12500 -- -- -- -- --

75 50000 41687 41667 30000 26667 25000 25000 20000 20800 20000 16667 -- 15000 -- -- 12500 -- --

76 60000 50000 50000 40000 333333 33333 30000 26667 25000 25000 20000 20800 20000 16667 -- 15000 -- --

77 80000 66667 66667 50000 40000 41667 40000 33333 33333 30000 26667 25000 25000 20000 20800 20000 16667 --

78 100000 83333 83333 60000 53333 50000 50000 40000 41667 40000 33333 33333 30000 26667 25000 25000 20000 20800

79 -- 100000 100000 80000 66667 66667 60000 53333 50000 50000 40000 41667 40000 33333 33333 30000 26667 25000

80 -- 133333 133333 100000 80000 83333 80000 66667 66667 60000 53333 50000 50000 40000 41667 40000 33333 33333

81 -- -- 166667 -- 106667 100000 100000 80000 83333 80000 66667 66667 60000 53333 50000 50000 40000 41667

82 -- -- 200000 -- 133333 133333 -- 106667 100000 100000 80000 83333 80000 66667 66667 60000 53333 50000

83 -- -- 250000 -- -- 166667 -- 133333 133333 -- 106667 100000 100000 80000 83333 80000 66667 66667

84 -- -- 300000 -- -- 200000 -- -- 166667 -- 133333 133333 -- 106667 100000 100000 80000 83333

85 -- -- 400000 -- -- 250000 -- -- 200000 -- -- 166667 -- 133333 133333 -- 10667 100000

86 -- -- -- -- -- 300000 -- -- 250000 -- -- 200000 -- -- 166667 -- 133333 133333

87 -- -- -- -- -- 400000 -- -- 300000 -- -- 250000 -- -- 200000 -- -- 166667

88 -- -- -- -- -- -- -- -- 400000 -- -- 300000 -- -- 250000 -- -- 200000

89 -- -- -- -- -- -- -- -- -- -- -- 400000 -- -- 300000 -- -- 250000

90 -- -- -- -- -- -- -- -- -- -- -- -- -- -- 400000 -- -- 300000

91 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 400000

* Classes of cooling (see 2.6.1 of American National Standard C57.12.00-1988).

** First- and second-stage auxiliary cooling (see TR 1.0.02).

† For column 2 and 3 ratings, the sound levels are with the auxiliary cooling equipment in

operation.

†† For intermediate kVA ratings, use the average sound level of the next larger kVA rating.

The equivalent two-winding 55°C or 65°C rating is defined on one-half the sum of the kVA of

all windings.

 Sixty-seven decibels for all kVA ratings equal to this or smaller
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Required sound levels in dBs (based on the ANSI weighting network “A” response or dBA scale) will

vary from one situation to another. Levels sometimes prescribed in ordinances may be approximately 45

dB at night and 55 dB in daytime. These levels may apply only to a potential source of complaint or at

the substation boundaries. For comparison, a NEMA-standard-designed 20,000 kVA two-winding

substation transformer with 350 kV BIL and first stage of auxiliary cooling would have an average sound

level of 72 dB. (See Pedersen 1956; Schulz 1976.)

5.2.12.5 Barriers: Sound barriers located near the transformer can be considered in special cases

(especially at existing installations) as a means of reducing noise levels in the vicinity. Barriers can

produce a maximum reduction of approximately 20 dB. A total enclosure can produce a 40-dB reduction.

For partial barriers, a reduction of 15 dB is a practical maximum. The effect of the barriers on

transformer cooling and transformer removal should also be considered.

5.2.13 Tank

In most cases, the manufacturer’s standard provisions related to the transformer tank will meet

requirements for filling and draining, oil sampling, handling, internal inspection, etc. Any special

requirements or preferences should be considered at the time specifications are written and their possible

extra cost evaluated. Some items to consider are:

• Preferred location of heat exchangers

• Preferred location and height of cabinets and other accessories above transformer base

• Construction of terminal boards

• Paint color

• Provisions for future additions

5.2.14 Accessories

Various accessories are available for use with power transformers. Many of these are standard items

normally supplied with the basic transformer while others are special items available at extra cost. Items

supplied as standard are listed in ANSI/IEEE Std. C57.12.10, Section 5. Some accessories not furnished

as standard items but that may be desired are special bushings, current transformers, bushing capacitance

potential taps, bushing potential device(s), auxiliary power provisions, special relays, special terminals,

spare parts, etc.

5.2.15 Electrical Tests and Measurements

5.2.15.1 Dielectric Tests: Dielectric tests consist of a variety of tests, each performed to prove a

certain characteristic of the transformer insulation structure. (See ANSI/IEEE Stds. C57.12.90 and

C57.98 for complete information on tests.) Dielectric tests are generally specified only on the larger sizes

of transformers or on smaller transformers used in especially important applications. Most manufacturers

charge for these tests. Table 5-18 provides guidelines for specifying dielectric tests.

5.2.15.1.1 Full Wave Impulse Test: The full wave impulse test (1.2 x 50-microsecond wave) is

designed to simulate a lightning stroke. Because of its relatively long duration, the full wave impulse test

causes major oscillations to develop in the winding. Consequently, not only turn-to-turn and section-tosection insulation are stressed throughout the winding but relatively high voltages can result, compared to

power frequency stresses, across large portions of the winding and between the winding and ground (core

and adjacent windings).
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Table 5-18: Guidelines for Specification of Dielectric Tests

on Power Transformers Rated 345 kV and Below

10,000 kVA (OA)

or Less Mfr’s

Quality Assurance

Only* 

Above 10,000 kVA (OA)

Purchaser’s

Specifications** 

Reduced Full Wave Yes Yes

Chopped Wave

 (2 shots)

Yes Yes

Full Wave Yes Yes

Low-Frequency Tests Yes Yes

Partial Discharge

 (Internal Corona)

Usually None Yes

* Manufacturers’ practices regarding quality assurance tests will vary from one manufacturer to

another. When these tests are performed, no official report is provided to the customer.

** Purchaser’s Specification should specify that the dielectric tests shall be performed in accordance

with ANSI Standards. An official manufacturer’s report should be required.

5.2.15.1.2 Chopped Wave Impulse Test: The chopped wave impulse test (similar to the full wave

test but 15 percent higher and chopped on the tail in about 3 μs or less), because of its shorter duration,

does not allow the major oscillations to develop as fully. It is designed to simulate a lightning stroke

truncated by a flashover on an adjacent portion of the insulation system. This test generally does not

produce as high voltages across large portions of the winding or between the winding and ground.

However, because of its greater amplitude, it produces high voltages at the line end of the winding and,

because of the rapid change of voltage following flashover of the test gap, it produces higher turn-to-turn

and section-to-section stresses.

5.2.15.1.3 Front-of-Wave Impulse Test: The front-of-wave impulse test (similar to the chopped

wave test but chopped on the front and with a much steeper front) is still shorter in duration and produces

still lower winding-to-ground voltages deep within the winding. Near the line end, however, its greater

amplitude produces higher voltages from winding to ground, and this, combined with the rapid change of

voltage on the front and following flashover, produces high turn-to-turn and section-to-section voltages

near the line end of the winding.

5.2.15.1.4 Switching Surge Test: The switching surge test is related to the other impulse tests, but

has a much longer wave front and tail. This slow wave fully penetrates the windings and stresses all parts

of the insulation structure.

5.2.15.1.5 Applied Voltage Test: An applied voltage test measures the ability of the transformer to

survive at normal frequency overvoltage. It also determines the increase in exciting current.

5.2.15.1.6 Induced Voltage Test: An induced voltage test measures the insulation strength between

turns in the winding and the insulation strength of barriers and other major insulation between phases.

During this test, a partial discharge (corona) test can be conducted to determine presence, inception, and

extinction levels of partial discharges that may be damaging to the insulation structure and eventually lead

to failure.

The partial discharge (corona) test consists of measuring the 1 megahertz (by agreement between

manufacturers and users) portion of any pulses produced within the transformer during low-frequency
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tests and that show up at the transformer terminals. The low-frequency tests are usually performed using

120 to 240 hertz voltages. The magnitude of the partial discharge is expressed in microvolts.

Most manufacturers take the measurements from each bushing capacitance tap, when these taps are

available. A calibration procedure is used to convert the tap readings to an equivalent value at the

bushing terminal.

5.2.15.2 Measurements (Electrical): Measurements that produce data required for operation of the

transformer include resistance, core and conductor losses, excitation current, impedance, ratio and

regulation temperature rise, insulation power factor, polarity and phase relation, etc. Consult ANSI/IEEE

Std. C57.12.90 for detailed information regarding these test measurements.

5.2.16 Shipment

Several shipping considerations are important. During shipping, the transformer may be subjected to its

most severe test due to rough handling. Acceleration measuring devices (impact recorder) mounted on

the transformer during shipment will help to determine whether the transformer may have been subjected

to excessive forces. In any case, make a thorough inspection of the interior of the transformer to

determine whether movement of the core and coils has taken place or whether evidence of any other

damage exists.

Larger size transformers are shipped without oil but sealed with either a blanket of nitrogen gas or dry air.

The method used often varies with the transformer manufacturer. Either method is considered

satisfactory, provided proper safety precautions are taken and warning signs are exhibited to deter a

person from entering an unsafe tank before it has been purged with proper amounts of air or oxygen.

It is good practice to provide the manufacturer with all necessary information regarding the situation at

the final destination. This will enable shipment to be made in the most convenient way. Sometimes it is

important for the transformer to be positioned a particular way by the final carrier to facilitate unloading

at the site.

5.2.17 Warranty

In general, transformer manufacturers warrant their product to be free of defects in workmanship and

material for a specified period. In the event of a defect, the manufacturer may elect to correct the problem

at his option either by repairing the defective part or parts or by supplying a repaired or replacement part

or parts. Under terms of a normal warranty, the manufacturer assumes no responsibility for disassembly

or reassembly of the equipment or return transportation from the field to the factory and back to the field.

Since warranties are subject to many variables, the purchaser is cautioned to exercise care in review and

evaluation of each one. Warranty periods vary from one to five years or more. Special warranties are

available, at some increase in purchase price, that extend the warranty period and/or include the cost of

removing a failed transformer from the field, returning it to the factory, repair, return to the field,

reinstallation in the field, etc.

5.2.18 Core and Coils

Transformers can be classified by two different forms of construction: “core form” or “shell form.” Most

common is the core-form type manufactured either with cylindrical coils wrapped horizontally around a

cylindrical core or with rectangular coils and a rectangular core. Core-form transformers have excellent
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short-circuit capability for most applications. The shell-form transformer is manufactured with the coils

wrapped through the core vertically. Shell-form transformers were developed for very large, highmagnitude short-circuit application such as generator step-up transformers.

5.2.19 Specifications

Purchase specifications should be based on standards of national organizations such as ANSI, IEEE,

NEMA, etc. However, when the desired power transformer is included in RUS IP 202-1, “List of

Materials Acceptable for Use on Systems of RUS Electrification Borrowers,” specification need only

cover such details as voltage, kVA ratings, optional tests, and features or accessories that are offered by

the manufacturer and considered necessary or desirable. The basic requirements for transformers in the

List of Materials are given in the ANSI/IEEE Standards C57 series and should not be included in the

purchase specification. The latest List of Materials includes step-down power transformers in the

following sizes and voltage ratings:

Primary Voltage Rating Capacity, kVA

Single-Phase 138 kV and below 10,000 kVA (OA) and below

Three-Phase 138 kV and below 30,000 kVA (OA) and below

Purchase specifications for transformers that are not included in the List of Materials should be detailed

enough to provide reasonable assurance that the transformer will be suitable for its intended use. In

general, the specification should be based on functional and operational requirements rather than

construction and design requirements, since the latter are properly the responsibility of the manufacturer.

It is very important that the user review the “usual” and “unusual” operating conditions listed in “General

Requirements Standards” such as ANSI/IEEE Std. C57.12.00 and ANSI/IEEE C57.12.01. Any unusual or

special operating or environmental condition should be made known to the manufacturer.

It is recommended that the purchase specifications be modeled on or checked against the requirements of

ANSI Std. C57.97, “Guide for Preparation of Specifications for Large Power Transformers, With or

Without Load Tap Changing.” In addition, it is recommended that a special requirement for short-circuit

current strength be included such as given in Section 5.2.9, Short-Circuit Requirements. The

manufacturer’s standard design should be accepted, and standard sizes, ratings, taps, and accessories

should be specified, unless there is a good reason for doing otherwise.

To assist in the evaluation of transformers being offered in a particular case, it is desirable to include in

the request for bids the method for evaluation of transformer losses. This should be patterned after RUS

Bulletin 1724E-301, “Guide for the Evaluation of Large Power Transformer Losses.” This information

will also assist the manufacturer in its efforts to offer the type of transformer desired.

5.2.20 References

ANSI Std. C57.12.10, “Safety Requirements 230 kV and Below 833/958 Through 8333/10 417 kVA,

Single-Phase, and 750/862 Through 60 000/80 000/100 000 kVA, Three-Phase Without Load Tap

Changing.”

ANSI Std. C57.12.20, “Transformers Overhead-Type Distribution Transformers, 500kVA and Smaller:

High Voltage, 34 500 Volts and Below; Low Voltage, 7970/13 800Y Volts and Below,” 1988.
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ANSI Std. C57.12.21, “Requirements for Pad-Mounted Compartmental-Type Self-Cooled Single-Phase

Distribution Transformers with High-Voltage Bushings (High-Voltage, 34 500 Grd Y/19 920

Volts and Below; Low Voltage, 240/210; 167 kVA and Smaller),” 1980.

ANSI Std. C57.12.22, “Requirements for Pad-Mounted Compartmental-Type, Self-Cooled Three-Phase

Distribution Transformers with High-Voltage Bushings, 2500 kVA and Smaller: High-Voltage,

34 500 Grd Y/19 920 Volts and Below; Low Voltage, 480 Volts and Below,” 1988.

ANSI Std. C57.12.23, “Standard for Transformers—Underground-Type, Self-Cooled, Single-Phase

Distribution Transformers with Separable, Insulated High-Voltage Connectors: High Voltage (24

940 Grd/ 14 400 Volts and Below) and Low Voltage (240/120 Volts, 167 kVA and Smaller),”

1986.

ANSI Std. C57.12.24, “Standard for Transformers—Underground-Type, Three-Phase Distribution

Transformers, 2500 kVA and Smaller: High Voltage 34 500 Grd Y/19 920 Volts and Below; Low

Voltage, 480 Volts and Below—Requirements,” 1992.

ANSI Std. C57.12.25, “Requirements for Pad-Mounted Compartmental-Type Self-Cooled Single-Phase

Distribution Transformers with Separable Insulated High-Voltage Connectors, High-Voltage,

34 500 Grd Y/19920 Volts and Below; Low-Voltage, 240/210; 167 kVA and Smaller,” 1990.

ANSI Std. C57.12.26, “Requirements for Pad-Mounted Compartmental-Type Self-Cooled Three-Phase

Distribution Transformers with Separable Insulated High-Voltage Connectors, High-Voltage,

34500 Grd Y/19920 Volts and Below; 2500 kVA and Smaller,” 1992.

ANSI Std. C57.12.70, “Terminal Markings and Connections for Distribution and Power Transformers.”

ANSI Std. C57.97, “ANSI Guide for Preparation of Specifications for Large Power Transformers, With

or Without Load Tap Changing.”

ANSI Std. C76.1, “Outdoor Apparatus Bushings.”

ANSI Std. C84.1, “Electric Power Systems and Equipment—Voltage Ratings.”

ANSI Std. C92-2, “Preferred Voltage Ratings of Alternating-Current Electrical Systems and Equipment

Operating at Voltages Above 230 kV Nominal,” 1987.

ANSI/IEEE Std. C57.10.101, “Draft, Trial-Use Guide for Loading Power Apparatus Bushings.”

ANSI/IEEE Std. C57.12.00, “Distribution, Power and Regulating Transformers, General Requirements

for Liquid-Immersed.”

ANSI/IEEE Std. C57.12.01, “Standard General Requirements for Dry-Type Distribution and Power

Transformers.”

ANSI/IEEE Std. C57.12.11, “Guide for Installation of Liquid-Immersed Transformers (10 MVA and

Larger, 69-287 kV Rating).”

ANSI/IEEE Std. C57.12.80, “Transformer Terminology.”
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ANSI/IEEE Std. C57.12.90, “Standard Test Code for Liquid-Immersed Distribution, Power, and

Regulating Transformers and Guide for Short Circuit Testing of Distribution and Power

Transformers.”

ANSI/IEEE Std. C57.19.00, “Draft, Standard General Requirements and Test Procedure for Outdoor

Apparatus Bushings.”

ANSI/IEEE Std. C57.19.01, “Draft, Standard Performance Characteristics and Dimensions for Outdoor

Apparatus Bushings.”

ANSI/IEEE Std. C57.92, “Guide for Loading Mineral Oil-Immersed Power Transformers up to and

Including 100 MVA with 55°C or 65°C Average Winding Rise.”

ANSI/IEEE Std. C57.98, “Guide for Transformer Impulse Tests.”

ANSI/IEEE Std. C57.109, “Guide for Through-Fault-Current Duration.”

ANSI/IEEE Std. C57.116, “Guide for Transformers Connected to Generators.”

IEEE Std. C57.104, “Draft, Guide for Interpretation of Gases Generated in Oil-Immersed Transformers.”

IEEE Std. C57.106, “Draft, Guide for Acceptance and Maintenance of Insulating Oil in Equipment.”

NEMA Std. TR1, “Transformers, Regulators and Reactors.”

Pedersen, R.S., “Audible Noise Reduction,” Transmission and Distribution, November 1956.

RUS Bulletin 50-91, “RUS Specification for Step-Down Distribution Substation Transformers.”

RUS Bulletin 61-16, “Guide for Economic Evaluation of Distribution Transformers.”

RUS Bulletin 1724E-301, “Guide for the Evaluation of Large Power Transformer Losses.”

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”

Schulz, M.W. (Member IEEE, General Electric Company, Schenectady, New York). “Transformer

Audible Noise.” Presented as part of an IEEE Tutorial Course on “Application of Distribution

and Power Transformers” Organized by W.J. McNutt, Fellow, IEEE, General Electric Company,

Pittsfield, Mass., April 1976.

5.3 POWER CIRCUIT BREAKERS

5.3.1 General

By definition, a circuit breaker is a device that closes and interrupts (opens) an electric circuit between

separable contacts under both load and fault conditions, as prescribed in the C37 series of ANSI

Standards. This discussion is limited to circuit breakers rated 1000 volts and above. (Automatic circuit

reclosers are discussed in Section 5.9.)
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5.3.1.1 Prerequisites to Specification: The application of circuit breakers involves consideration of

the intended function, expected results, benefits to the electric system, and characteristics of both the

circuit breakers and the electric system. In some instances, protective devices of lesser capability and

flexibility, such as fuses, circuit switchers, reclosers, etc., may be more desirable or preferred over more

complex and costly circuit breakers.

Fuses are often desirable for transformer protection at any location where they are adequate for the

thermal load and short-circuit conditions because of their lower cost and smaller space requirements

compared to other devices. They are also desirable for their ease of coordination with circuit breakers and

relays at other locations on the electric system. Fuses can also be applied as temporary maintenance

bypass protection to permit maintenance of circuit breakers. Fuses are also used extensively for

sectionalization and branch circuit protection in distribution systems.

Circuit switchers are less costly than circuit breakers and can be applied in much the same way as circuit

breakers, subject to limitations in interrupting capability, with the same type of relay control as circuit

breakers. Circuit switchers are also supplied without current transformers (circuit breakers are usually

supplied with CTs), which are used in conjunction with relays to sense faults. They can be substituted for

fuses in transformer bank protection to detect low-voltage-side faults that fuses may not be able to detect.

This detection would utilize relay intelligence from the low-voltage side. Circuit switchers also provide

excellent capacitor bank switching and protection. In outlying areas of moderate short-circuit capacity,

they can often be substituted for circuit breakers. They can be mounted similarly to air-break switches on

a substation structure and thus require little or no additional space.

Reclosers are completely self-contained and provide excellent distribution circuit exit and feeder

protection. Their ratings are adequate for both load and short circuit on most distribution circuits and

overlap the ratings of more costly circuit breakers. Their operation is faster than most circuit breakers,

and their sequence of open and close operations is very flexible. Reclosers are available in both singleand three-phase ratings so that they are very useful and adaptable for the entire distribution system at

locations where reclosing operation is required.

Writing of specifications and selection of power circuit breakers and similar devices should be preceded

by electric system studies to determine the parameters of application and operation that have to be

satisfied. These include load flow, short-circuit, transient voltage, coordination, and protection studies.

5.3.1.2 Specification—General Requirements: Power circuit breakers are not included in RUS’s

“List of Materials.” Therefore, for each application, a detailed specification is necessary. A functional

specification describing the circuit breaker rating and control, electric system characteristics and any

special requirements is preferred to one describing design and construction details. ANSI Std. C37.12,

“American National Standard Guide Specifications for AC High-Voltage Circuit Breakers Rated on a

Symmetrical Current Basis and a Total Current Basis,” can be used directly as a model or checklist for the

purchase specification. A manufacturer’s standard design and construction would normally be considered

acceptable.

It is recommended that those persons responsible for preparing power circuit breaker specifications

become familiar with:

1. The C37 series of ANSI Standards covering ratings, testing, applications, specifications, etc.

2. Each specific application and proposed installation

3. Each prospective supplier’s product line of circuit breakers
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5.3.2 Types of Circuit Breakers

Breakers are usually classified as “dead tank” or “live tank” construction. “Dead tank” means that the

circuit breaker tank and all accessories are maintained at ground potential, and the external source and

load connections are made through conventional bushings (see Figure 5-2). “Live tank” means that the

metal and porcelain housing containing the interrupting mechanism is mounted on an insulating porcelain

column and is therefore at line potential (see Figure 5-3). This column, besides serving as an insulating

support, may act as an access for the operating rod or linkage and, in the case of air circuit breakers, it

acts as an air supply duct. Most circuit breakers above 242 kV are of “live tank” construction. However,

some dead tank-type units are in use.

In addition to classification as “live tank” or “dead tank” construction, circuit breakers are also classified

in terms of interrupting media. Breakers are also classified as three-pole, single-throw, and independentpole operation. Three-pole single-throw breakers utilize one mechanical device to trip all three poles with

a linkage to gang the operation together (see Figure 5-4). With independent-pole operation, each pole is

equipped with the mechanical means to trip its individual pole (see Figure 5-5). Although availability of

different breaker designs is closely related to the state of the art at any particular time, Table 5-19

indicates the known availability of breaker types.

Table 5-19: Types of Circuit Breakers

Availability vs. Interrupting Media

Outdoor Oil (1) Air Gas Vacuum

Dead Tank

Single Tank X X X

Three Tank X X X

Live Tank

Indoor X

Dead Tank X X X

(1) Oil circuit breakers are only available as remanufactured or used equipment.

No general guidelines can be drawn for the application of these various types of circuit breakers. Each

user has to determine the ratings of circuit breakers required and then select a type of circuit breaker

acceptable with regard to rating, performance expectations, compatibility with planned or existing

substation configuration, and the ability to install, operate, and maintain the circuit breaker. Cost may

also be an important consideration in the final selection.

Most, but not all, domestic circuit breakers in outdoor substations of 2.4 kV through 24.9 kV utilize a

vacuum technology as the insulating dielectric to interrupt load and fault currents (see Figure 5-6).

Although outdoor vacuum breakers can be supplied for voltages up to 38 kV, SF6 is more commonly used

for voltages from 34.5 kV to 765 kV.
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Figure 5-2: “Dead Tank” Breaker Figure 5-3: “Live Tank” Breaker

(Courtesy of Mitsubishi) (Courtesy of Mitsubishi)
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Figure 5-4: Three-Pole Single-Throw Breakers (Courtesy of Siemens)
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Figure 5-5: SF6 Gas Circuit Breakers (Courtesy of GE-Hitachi HVB, Inc.)
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Figure 5-6: Type SDV Vacuum Circuit Breaker (Courtesy of Siemens)
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SF6 breakers are available in 15 kV to 242 kV ratings in single tanks and in 15 kV to 800 kV ratings in

three (individual pole) tanks. Although SF6 breakers are available in single-tank designs, the trend is

toward three-tank. SF6 breaker manufacturers have been able to reduce the size of the interrupting

chambers, making the three-tank design more economical.

SF6 circuit breakers are available with three operating mechanisms: pneumatic, hydraulic, and springoperated. Some circuit breaker manufacturers have models for each of the operating mechanisms.

Because of the differences between manufacturers and operating mechanisms, a discussion of

maintenance and inspection procedures has been left up to the individual manufacturers. Although there

are many differences, most circuit breakers require the bushings to be removed to expose the interrupting

mechanism for inspection and maintenance.

Although there are a number of oil circuit breakers still in service, with the developments in SF6 and

vacuum technology, oil breakers are being phased out. Some companies sell oil breakers, but as used and

reconditioned breakers.

5.3.3 Ratings

The rating of a circuit breaker is a summary of its characteristics that identifies its application on an

electric system, its performance capabilities, and its adaptability. This summary of characteristics is

given principally in terms of voltages, currents, and time as described in the rating tables, in the ANSI

C37 Standards, and in the following subsections.

5.3.3.1 Voltage: Voltage characteristics are defined in terms of rms nominal, rms rated maximum,

rated voltage range factor, and rated dielectric strength.

5.3.3.1.1 Nominal Voltage : Nominal voltage, also known as voltage class, is used to identify the

general voltage class or electric system voltage on which a particular circuit breaker was intended for

application.

5.3.3.1.2 Rated Maximum Voltage: Rated maximum voltage is the maximum voltage for which the

circuit breaker is designed and is also the upper limit for operation on an electric system. It is based on

ANSI Std. C84.1, “American National Standard Voltage Ratings for Electric Power Systems and

Equipment (60 Hz),” and ANSI Std. C92.2, “Preferred Voltage Ratings for Alternating Current Electrical

Systems and Equipment Operating at Voltages Above 230 Kilovolts Nominal.” It is the prime operating

voltage reference and relates the rated short-circuit interrupting current and short-circuit interrupting kA

or energy handling capabilities.

5.3.3.1.3 Rated Voltage Range Factor: Rated voltage range factor, designated as “K,” defines the

lower limit of operating voltage at which the required symmetrical and asymmetrical current interrupting

capabilities vary in inverse proportion to the operating voltage.

“K” is the ratio of rated maximum voltage to this lower limit of operating voltage. The rated maximum

voltage either divided by K or multiplied by the reciprocal, 1/K will produce the lower limit of operating

voltage. See Table 5-20 for 72.5 kV through 800 kV circuit breakers, where the voltage range factor is

1.0. This limits the maximum interrupting current capability at voltages lower than rated voltage to a

value no greater than the interrupting current capability at rated maximum voltage.
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Table 5-20: Preferred Ratings for Indoor Circuit Breakers with Voltage Range Factor K = 1.0.*

Ref. ANSI/IEEE Std. C37.06-1997, Table 1.

Reproduced with permission of the National Electrical Manufacturers Association.

Rated Transient Recovery

Voltages (3)

Rated

Maximum

Voltage (1)

kV, rms

Rated

Voltage

Range

Factor K

Rated

Continuous

Current

Amperes, rms

Rated

ShortCircuit and

Short-Time

Current

kA, rms

Rated

Peak

Voltage E2

kV, peak

Rated

Time to

Peak T2

(4) μsec

Rated

Interrupting

Time (5)

ms

Rated

Permissible

Tripping

Delay

Time

Y sec

Rated

Closing

and

Latching

Current (2)

Line kA, peak

No. Col 1 Col 2 Col 3 Col 4 Col 5 Col 6 Col 7 Col 8 Col 9

1 4.76 1.0 1200, 2000 31.5 8.9 50 83 2 82

2 4.76 1.0 1200, 2000 40 8.9 50 83 2 104

3 4.76 1.0 1200, 2000,

3000

50 8.9 50 83 2 130

4 8.25 1.0 1200, 2000,

3000

40 15.5 60 83 2 104

5 15 1.0 1200, 2000 20 28 75 83 2 52

6 15 1.0 1200, 2000 25 28 75 83 2 65

7 15 1.0 1200, 2000 31.5 28 75 83 2 82

8 15 1.0 1200, 2000,

3000

40 28 75 83 2 104

9 15 1.0 1200, 2000,

3000

50 28 75 83 2 130

10 27 1.0 1200 16 51 105 83 2 42

11 27 1.0 1200, 2000 25 51 105 83 2 65

12 38 1.0 1200 16 71 125 83 2 42

13 38 1.0 1200, 2000 25 71 125 83 2 65

14 38 1.0 1200, 2000,

3000

31.5 71 125 83 2 82

15 38 1.0 1200, 2000,

3000

40 71 125 83 2 104

* For preferred capacitance current switching rating, see ANSI/IEEE C37.06-1997 Table 1A.

For preferred dielectric ratings, see Table 5-22.

For circuit breakers with a rated voltage range factor K greater than 1.0, see Tables 5-21 and ANSI/IEEE Std. C37.06-1997 A1A.

See notes following Table 5-21.
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For 4.76 kV through 38.0 kV circuit breakers, Table 5-21 shows a rated maximum voltage related to an

interrupting kA, rms rating. These circuit breakers all have a voltage range factor greater than 1.0, which

permits operation at lower than rated voltage and a maximum interrupting current of K times rated

interrupting current as described above.

5.3.3.1.4 Example (Table 5-21):

Circuit breaker rated 18 kA interrupting capacity, maximum operating voltage 15.0 kV, voltage range

factor K = 1.30.

Calculate maximum interrupting current, I = (18)(1.3) = 23 kA.

Lower operating voltage limit, E = 15/1.3= 11.5 kV.

5.3.3.1.5 Rated Dielectric Strength: The rated dielectric strength of a circuit breaker is its voltage

withstand capability with specified magnitudes and waveshapes of test voltage applied under specific test

conditions. The schedule of dielectric tests for power circuit breakers includes values for low frequency

and impulse. These values are fixed and are related directly to rated maximum voltage of breakers.

Dielectric test values for outdoor ac high-voltage power circuit breakers are shown in Table 4 of ANSI

Std. C37.06 (see Table 5-22).

5.3.3.2 Current: Current characteristics are defined as follows:

5.3.3.2.1 Rated Continuous Current: The rated continuous current of a circuit breaker is the

designated limit of current in rms amperes at rated frequency that it is required to carry continuously

without exceeding any of the limitations designated in ANSI Std. C37.06. (Refer to Tables 5-20, 5-21,

5-23 and 5-24.)
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Table 5-21: Preferred Ratings for Indoor Circuit Breakers with Voltage Range Factor K >1.0*

Ref. ANSI/IEEE Std. C37.06-1997, Table A1.

Reproduced with permission of the National Electrical Manufacturers Association.

Transient Recovery Voltages (9)

Rated

Maximum

Voltage (1)

kV, rms

Rated

Voltage

Range

Factor K

(2)

Rated

Continuous

Current at

60 Hz (3)

Amperes

Rated

ShortCircuit

Current Δ

(at Rated

Maximum

kV)

(4)(5)(6)(10)

kA, rms

Rated Time

to

Point P T2β

μsec

Rated Rate

R

kV / μ sec

Rated

Delay

Time T1 μ

sec

Rated

Interrupting

Time

(7)cycles

Rated

Maximum

Voltage

Divided by

K

kV, rms

Maximum

Symmetrical

Interrupting

Capability

and

Rated ShortTime

Current

(4)(5)(8) kA,

rms

Closing

and

Latching

Capability

2.7K times

Rated

ShortCircuit (4),

kA, Crest

4.76 1.36 1200 8.8 -- -- -- 5 3.5 12 32

4.76 1.24 1200, 2000 29 -- -- -- 5 3.85 36 97

4.76 1.19 1200, 2000,

3000

41 -- -- -- 5 4.0 49 132

8.25 1.25 1200, 2000 33 -- -- -- 5 6.6 41 111

15.0 1.30 1200, 2000 18 -- -- -- 5 11.5 23 62

15.0 1.30 1200, 2000 28 -- -- -- 5 11.5 36 97

15.0 1.30 1200, 2000,

3000

37 -- -- -- 5 11.5 48 130

38.0 1.65 1200, 2000,

3000

21 -- -- -- 5 23.0 35 95

38.0 1.0 1200, 3000 40 -- -- -- 5 38.0 40 108

* For rated dielectric test values, see Table 5-22.

Δ For the related required capabilities associated with the rated short-circuit current of the circuit breaker, see note 4.

β These rated values are not yet standardized. Work is in progress.
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Notes for Tables 5-20 and 5-21

(Numbers in parentheses in the tables refer to the following correspondingly numbered notes)

For service conditions, definitions, and interpretation of ratings, tests, and qualifying terms, see

ANSI/IEEE Std. 37.04-1979, ANSI/IEEE Std. C37.09-1979, and ANSI/IEEE Std. C37.100-1981.

The interrupting ratings are for 60-Hz systems. Applications on 25-Hz systems should receive special

consideration.

Current values have been rounded off to the nearest kiloampere (kA) except that two significant figures

are used for values below 10 kA.

(1) The voltage rating is based on ANSI C84.1-1982, where applicable, and is the maximum voltage for

which the breaker is designed and the upper limit for operation.

(2) The rated voltage range factor, K, is the ratio of rated maximum voltage to the lower limit of the

range of operating voltage in which the required symmetrical and asymmetrical current interrupting

capabilities vary in inverse proportion to the operating voltage.

(3) The 25-Hz continuous current ratings in amperes are given herewith following the respective 60-Hz

rating: 600-700; 1200-1400; 2000-2250; 3000-3500.

(4) Related Required Capabilities. The following related required capabilities are associated with the

short-circuit current rating of the circuit breaker.

(a) Maximum symmetrical interrupting capability (kA, rms) of the circuit breaker is equal to K times

rated short-circuit current.

(b) 3-second short-time current carrying capability (kA, rms) of the circuit breaker is equal to K

times rated short-circuit current.

(c) Closing and latching capability (kA, rms) of the circuit breaker is equal to 1.6 K times rated

short-circuit current. If expressed in peak amperes, the value is equal to 2.7 K times rated

short-circuit current.

(d) 3-second short-time current carrying capability and closing and latching capability are

independent of operating voltage up to and including rated maximum voltage.

(5) To obtain the required symmetrical current interrupting capability of a circuit breaker at an operating

voltage between 1/K times rated maximum voltage and rated maximum voltage, the following

formula shall be used:

Required symmetrical current interrupting capability = rated short-circuit current x (rated maximum voltage)

(operating voltage)

For operating voltages below 1/K times rated maximum voltage, the required symmetrical current

interrupting capability of the circuit breaker shall be equal to K times rated short-circuit current.

(6) With the limitation stated in 5.10 of ANSI/IEEE C37.04-1979, all values apply for polyphase and lineto-line faults. For single-phase-to-ground faults, the specific conditions stated in 5.10.2.3 of

ANSI/IEEE C37.04-1979 apply.

(7) The ratings in this column are on a 60-Hz basis and are the maximum time interval to be expected

during a breaker opening operation between the instant of energizing the trip circuit and interruption

of the main circuit on the primary arcing contacts under certain specified conditions. The values may

be exceeded under certain conditions as specified in 5.7 of ANSI/IEEE Std. C37.04-1979.

(8) Current values in this column are not to be exceeded even for operating voltages below 1/K times

rated maximum voltage. For voltages between rated maximum voltage and 1/K rated maximum

voltage, follow (5) above.

(9) The rated values for T2 are not standardized for indoor oilless circuit breakers; however, E2 = 1.88

times rated maximum voltage.

(10) Rated permissible tripping delay time (Y) = 2 seconds.
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231

Table 5-22: Preferred Dielectric Withstand Ratings and External Insulation. Ref. ANSI/IEEE Std. C37.06-1997, Table 4.

Reproduced with permission of the National Electrical Manufacturers Association.

Power Frequency Impulse Test 1.2 x 50 μsec wave (a) Switching Impulse

Chopped Wave

kV Peak

Minimum Time to

Rated Sparkover

Maximu

m

Voltage

kV, rms

Rating

Table

No.

1 minute

Dry

kV, rms

10

seconds

Wet

kV, rms

Full Wave

(2)

Withstand

kV, Peak

2 μsec

Withstan

d

3 μsec

Withstand

Withstand

Voltage

Terminal to

Ground with

Breaker Closed

kV, Peak

Withstand

Voltage

Terminal to

Terminal on

One Phase

with Circuit

Breaker Open

kV, Peak

Minimum

Creepage

Distance of

External

Insulation to

Ground,

Line Inches

No. Col 1 Col 2 Col 3 Col 4 Col 5 Col 6 Col 7 Col 8 Col 9 Col 10

1 4.76 1 19 (3) 60 (3) (3) (3) (3) (3)

2 8.25 1 36 (3) 95 (3) (3) (3) (3) (3)

3 15.0 1 36 (3) 95 (3) (3) (3) (3) (3)

4 15.5 2 50 45 110 142 126 (3) (3) 9 (0.23m)

5 25.8 2 60 50 150 194 172 (3) (3) 15 (0.38m)

6 25.8 (4) 2 60 50 125 (3) (3) (3) (3) 15 (0.38m)

7 27.0 1 60 (3) 125 (3) (3) (3) (3) (3)

8 38.0 1 80 (3) 150 (3) (3) (3) (3) (3)

9 38.0 2 80 75 200 258 230 (3) (3) 22 (0.56m)

10 38.0 (4) 2 80 75 150 (3) (3) (3) (3) 22 (0.56m)

11 48.3 2 105 95 250 322 288 (3) (3) 28(0.71m)

12 72.5 2 160 140 350 452 402 (3) (3) 42 (1.07m)

13 123 3 260 230 550 710 632 (3) (3) 70 (1.78m)

14 145 3 310 275 650 838 748 (3) (3) 84 (2.13m)

15 170 3 365 315 750 968 862 (3) (3) 93 (2.49m)

16 245 3 425 350 900 1160 1040 (3) (3) 140 (3.56m)

17 362 3 555 (3) 1300 1680 1500 825 900 209 (5.31m)

18 550 3 860 (3) 1800 2320 2070 1175 1300 318 (8.08m)

19 800 3 960 (3) 2050 2640 2360 1425 1500 442

(11.23m)

NOTES:

(1) For circuit breakers applied in gas-insulated substations, see ANSI/IEEE Std. C37.06-1997, Table 5.

(2) 1.2 x 50 μ seconds positive and negative wave as defined in IEEE Std. 4. All impulse values are phase-to-phase and phase-to-ground and across the

open contact.

(3) Not required.

(4) These circuit breakers are intended for application on grounded-wye distribution circuits equipped with surge arresters.
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Table 5-23: Preferred Ratings for Outdoor Circuit Breakers 72.5 kV and Below,

Including Circuit Breakers Applied in Gas-Insulated Substations.* Ref. ANSI/IEEE Std. C37.06-1997, Table 2.

Reproduced with permission of the National Electrical Manufacturers Association.

Rated Transient Recovery

Voltages (3)

Rated

Maximum

Voltage (1)

kV, rms

Rated

Voltage

Range

Factor

K

Rated

Continuous

Current

Amperes,

rms

Rated

ShortCircuit and

ShortTime

Current

kA, rms

Rated

Peak

Voltage E2

kV, peak

Rated

Time to

Peak

T2 (4)

μsec

Rated

Interrupting

Time (5)

ms

Rated

Permissible

Tripping

Delay

Time Y

sec

Rated

Closing and

Latching

Current (2)

Line kA, peak

No. Col 1 Col 2 Col 3 Col 4 Col 5 Col 6 Col 7 Col 8 Col 9

1 15.5 1.0 600, 1200 12.5 29 36 83 2 33

2 15.5 1.0 1200, 2000 20.0 29 36 83 2 52

3 15.5 1.0 1200, 2000 25.0 29 36 83 2 65

4 15.5 1.0 1200, 2000,

3000

40.0 29 36 83 2 104

5 25.8 1.0 1200, 2000 12.5 48.5 52 83 2 33

6 25.8 1.0 1200, 2000 25.0 48.5 52 83 2 65

7 38.0 1.0 1200, 2000 16.0 71 63 83 2 42

8 38.0 1.0 1200, 2000 20.0 71 63 83 2 52

9 38.0 1.0 1200, 2000 25.0 71 63 83 2 65

10 38.0 1.0 1200, 2000 31.5 71 63 83 2 82

11 38.0 1.0 1200, 2000,

3000

40.0 71 63 83 2 104

12 48.3 1.0 1200, 2000 20.0 91 80 83 2 52

13 48.3 1.0 1200, 2000 31.5 91 80 83 2 82

14 48.3 1.0 1200, 2000,

3000

40.0 91 80 83 2 104

15 72.5 1.0 1200, 2000 20.0 136 106 83 2 52

16 72.5 1.0 1200, 2000 31.5 136 106 83 2 82

17 72.5 1.0 1200, 2000,

3000

40.0 136 106 83 2 104

* For rated dielectric test values, see Table 5-22 and ANSI/IEEE C37.06-1997 Table 5.

See notes following Table 5-24.
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233

Table 5-24: Preferred Ratings for Outdoor Circuit Breakers 121 kV and Above, Including Circuit Breakers

Applied in Gas-Insulated Substations.* Ref. ANSI/IEEE Std. C37.06-1997, Table 3.

Reproduced with permission of the National Electrical Manufacturers Association.

Rated Transient Recovery Voltages (6)

Rated

Maximum

Voltage (1)

kV, rms

Rated

Voltage

Range

Factor

K

Rated

Continuous

Current

Amperes, rms

Rated

ShortCircuit

and

ShortTime

Current

kA, rms

Rated

Time to

Peak

T2 (4)

μsec

Rated

Rate

R

kV/ μsec

Rated

Delay

Time

T1

μsec

Rated

Interrupting

Time (5)

ms

Rated

Permissible

Tripping

Delay

Time Y

sec

Rated

Closing and

Latching

Current

(2)

Line kA, peak

No. Col 1 Col 2 Col 3 Col 4 Col 5 Col 6 Col 7 Col 8 Col 9 Col 10

 1 123 1.0 1200 20 275 1.7 2 50 1 52

 2 123 1.0 1600, 2000, 3000 40 260 1.8 2 50 1 104

 3 123 1.0 2000, 3000 63 260 1.8 2 50 1 164

 4 145 1.0 1200 20 330 1.7 2 50 1 52

 5 145 1.0 1600, 2000, 3000 40 310 1.8 2 50 1 104

 6 145 1.0 2000, 3000 63 310 1.8 2 50 1 164

 7 145 1.0 2000, 3000 80 310 1.8 2 50 1 208

 8 170 1.0 1200 16 395 1.7 2 50 1 42

 9 170 1.0 1600 31.5 360 1.8 2 50 1 82

10 170 1.0 2000 40 360 1.8 2 50 1 104

11 170 1.0 2000 50 360 1.8 2 50 1 130

12 170 1.0 2000 63 360 1.8 2 50 1 164

13 245 1.0 1600, 2000, 3000 31.5 520 1.8 2 50 1 82

14 245 1.0 2000, 3000 40 520 1.8 2 50 1 104

15 245 1.0 2000 50 520 1.8 2 50 1 130

16 245 1.0 2000, 3000 63 520 1.8 2 50 1 164

17 362 1.0 2000, 3000 40 775 1.8 2 33 1 104

18 362 1.0 2000 63 775 1.8 2 33 1 164

19 550 1.0 2000, 3000 40 1325 1.6 2 33 1 104

20 550 1.0 3000 63 1325 1.6 2 33 1 164

21 800 1.0 2000, 3000 40 1530 1.9 2 33 1 104

22 800 1.0 3000 63 1530 1.9 2 33 1 164

* For preferred dielectric ratings, see Tables 5-22 and ANSI/IEEE C37.06-1997 Table 5.

See following notes.
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Notes for Tables 5-20, 5-23, and 5-24

(Numbers in parenthesis in the tables refer to the following correspondingly numbered notes)

For service conditions, definitions, interpretations of ratings, tests, and qualifying terms, see ANSI/IEEE

Std. C37.04, ANSI Std. 37.06.01, ANSI/IEEE Std. C37.09, and ANSI/IEEE Std. C37.100.

The preferred ratings are for 60-Hz systems. Applications at other system frequencies should receive

special considerations; see C37.010.

Current values have generally been rounded off to the nearest kiloampere (kA) except that two significant

figures are used for values below 10 kA.

(1) The voltage rating is based on ANSI C84.1, where applicable, and is the maximum voltage for

which the breaker is designed and the upper limit for operation.

(2) Rated closing and latching current (kA, peak) of the circuit breaker is 2.6 times the rated shortcircuit current. (If expressed in terms of kA, rms total current, the equivalent value is 1.55 times

rated short-circuit current.)

(3) Tables 1 and 2 only. The rated transient recovery voltage envelope is the “one-minus-cosine” (1-

cosine) shape. See Figure A1 in the appendix.

(4) If the source of power to a circuit breaker is a single transformer or a bank of transformers and

there are no substantial capacitors or loaded feeders connected to the source side of the circuit

breaker, the transient recovery voltage may be more severe than those covered in these tables. T2

values for these applications are being developed.

(5) The ratings in this column are the maximum time interval to be expected during a breaker opening

operation between the instant of energizing the trip circuit and the interruption of the main circuit on

the primary arcing contacts under certain specified conditions. The values may be exceeded under

certain conditions as specified in ANSI/IEEE Std. C37.04, sub-clause covering “Rated Interrupting

Time.”

(6) Table 3 only. The rated transient recovery voltage envelope is the “exponential-cosine” shape.

See Figure A2 in the Appendix. E2 = 1.76 times rated maximum voltage; E1 = 1.5/2/3 times rated

maximum voltage.

5.3.3.2.2 Altitude Correction Factors: For applications at altitudes higher than 3300 ft (1000 m), rated

dielectric strength and rated maximum voltage shall be multiplied by an altitude correction factor for

voltage, and current shall be multiplied by an altitude correction factor for current to obtain values at

which applications may be made. See Table 5-25 for altitude correction factors.

Table 5-25: Altitude Correction Factors (ACF)

for Voltage and Current. Ref. ANSI/IEEE Std. C37.04-1979,

Table 1. Copyright © 1979. IEEE. All rights reserved.

Altitude

(ft) (m)

ACF for

Voltage *#

ACF for

Continuous

Current*

3300 1000 1.00 1.00

5000 1500 0.95 0.99

10000 3000 0.80 0.96

* Interpolated values shall be used in determining correction factors for intermediate altitudes.

# For some types of circuit breakers (for example, those with sealed interrupters), it may not be

necessary to apply the ACF for voltages to rated maximum voltage. The manufacturer should be

consulted.
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5.3.3.2.3 Rated Short-Circuit Current: The rated short-circuit current of a circuit breaker is the

highest value of the symmetrical component of the polyphase or line-to-line short-circuit current in rms

amperes measured from the envelope of the current wave at the instant of primary arcing contact

separation that the circuit breaker is required to interrupt at rated maximum voltage and on the standard

operating duty. It also establishes, by fixed ratios as defined in ANSI/IEEE Std. C37.04-5.10.2, the

highest currents that the breaker is required to close and latch against, to carry, and to interrupt.

The relationship of rated short-circuit current to the other required capabilities is illustrated in Figures 5-7

and 5-8.

Figure 5-7: Relation of Symmetrical Interrupting Capability, Closing Capability,

Latching Capability, and Carrying Capability to Rated Short-Circuit Current.

Ref. ANSI/IEEE Std. C37.04-1979, Fig. 1. Copyright © 1979. IEEE. All rights reserved.
Bulletin 1724E-300

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Figure 5-8: Ratio of Circuit Breaker Asymmetrical to Symmetrical Interrupting Capabilities.

Ref. ANSI/IEEE Std. C37.04-1979, Fig. 2. Copyright © 1979. IEEE. All rights reserved.

5.3.3.2.4 Related Required Capabilities: In addition to the current ratings defined above,

symmetrically rated circuit breakers have related current capabilities. These related capabilities,

discussed in detail in ANSI/IEEE Std. C37.04, are essentially as follows:

5.3.3.2.4.1 Maximum Symmetrical Interrupting Capability: Maximum symmetrical interrupting

capability is K times rated short circuit.
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5.3.3.2.4.2 Current: These related required capabilities are based on a relay time of one-half cycle,

but may be used with any permissible tripping delay.

5.3.3.2.4.3 Required Symmetrical Interrupting Capability: Required symmetrical interrupting

capability of a circuit breaker for polyphase and line-to-line faults is the highest value of the symmetrical

component of the short-circuit current in rms amperes at the instant of primary arcing contact separation

that the circuit breaker shall be required to interrupt at a specified operating voltage on the standard

operating duty and irrespective of the direct current component of the total short-circuit current. The

numerical value at an operating voltage between 1/K times rated maximum voltage and rated maximum

voltage shall be determined using Equation 5-3:

Equation 5-3

Required

Symmetrical = Rated Short-Circuit Current x

Interrupting

Capability

In no case shall the required symmetrical interrupting capability exceed K times rated short-circuit

current.

5.3.3.2.4.4 Required Asymmetrical Interrupting Capability: Required asymmetrical interrupting

capability of a circuit breaker for polyphase and line-to-line faults is the highest value of the total shortcircuit current in rms amperes at the instant of primary arcing contact separation that the breaker shall be

required to interrupt at a specified operating voltage and on the standard operating duty.

The numerical value shall be equal to the product of a ratio S, specified below and illustrated in Figure

5-7, times the required symmetrical interrupting capability of the breaker determined for the operating

voltage. The values of S shall be 1.4, 1.3, 1.2, 1.1, or 1.0 for breakers having primary arcing contact

parting times of 1, 1.5, 2, 3, 4, or more cycles, respectively. The values of S for primary arcing contact

parting times between those given above shall be determined by linear interpolation. The primary arcing

contact parting time shall be considered equal to the sum of one-half cycle (present practical minimum

tripping delay) plus the lesser of the actual opening time of the particular breaker, or 1.0, 1.5, 2.5, or 3.5

cycles for breakers having a rated interrupting time of 2, 3, 5, or 8 cycles, respectively.

5.3.3.2.4.5 Required Symmetrical and Asymmetrical Interrupting Capability: Required symmetrical

and asymmetrical interrupting capability of a circuit breaker for single line-to-ground faults shall be 1.15

times the corresponding values specified for polyphase and line-to-line faults. In no case are the

capabilities for single line-to-ground faults required to exceed K times the symmetrical interrupting

capability (that is, K times rated short-circuit current) and K times the asymmetrical interrupting

capability, respectively, determined at rated maximum voltage.

5.3.3.2.4.6 Three-Second Short-Time Capability: Three-second short-time capability = K times

rated short-circuit current.

5.3.3.2.4.7 Closing and Latching Capability: Closing and latching capability 1.6 K times rated shortcircuit capability.

5.3.3.3 Interrupting Time : The rated interrupting time of a circuit breaker is the maximum

permissible interval between the energizing of the trip circuit at rated control voltage and the interruption

of the main circuit in all poles on an opening operation, when interrupting a current within its interrupting





























Operating Voltage

 Voltage

Rated Maximum
Bulletin 1724E-300

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capabilities. At duties below 25 percent of the asymmetrical interrupting capability at rated maximum

voltage, the circuit has to be interrupted, but the time required for interruption may be greater than the

rated interrupting time by as much as 50 percent for 5- and 8-cycle breakers and 1 cycle for 3-cycle

breakers. For breakers equipped with resistors, the interrupting time of the resistor current may be longer.

The interrupting time for a close–open operation at a specified duty should not exceed the rated

interrupting time by more than 1 cycle for 5- and 8-cycle breakers and one-half cycle for 3-cycle breakers.

When time is expressed in cycles, it should be on a 60-hertz basis.

5.3.3.4 Rated Permissible Tripping Delay: The rated permissible tripping delay of a circuit breaker

is Y seconds and is the maximum value of time for which the circuit breaker is required to carry K times

rated short-circuit current after closing on this current and before interrupting. For values, see ANSI

Std. C37.06.

5.3.3.5 Other Factors Affecting Rating: The factors noted above form the basis of rating breakers

complying with ANSI/IEEE Std. C37.04. Other factors that may affect breaker capability include duty

cycle, transient recovery voltage, reactive component of load, etc. These are discussed in detail in ANSI/

IEEE Std. C37.04.

In particular, the duty cycle of the circuit breaker has to be considered in its application. The duty is the

short-circuit current required to be interrupted, closed upon, etc. The cycle is a predetermined sequence

of closing and opening operations.

The standard duty cycle to which circuit breaker ratings are related is one closing plus one opening

operation, followed by a 15-second waiting period, followed by a second closing and a second opening

operation (CO + 15 Sec + CO). This duty cycle permits application of the circuit breaker at 100 percent

of its rating. Numerous other operating cycles and time intervals can be used. If the number of operating

cycles is greater and/or the time intervals are shorter than the standard duty cycle, derating of the breaker

interrupting capability is necessary according to the principles and procedures given in ANSI/IEEE

Std. C37.04.

5.3.4 Operating Mechanisms

The operating mechanism of a circuit breaker has to be designed to ensure positive or definite opening of

the circuit breaker, and circuit interruption has to occur whether the tripping or opening signal is received

with the circuit breaker fully closed or in any partially closed position. The operating mechanism should

also be capable of closing, reclosing and latching closed the circuit breaker when applied to the shortcircuit current shown in the rating tables (See Tables 5-20, 5-23, and 5-24).

Operating mechanisms can be provided with or for multiple-pole or independent-pole operation. The

term “operation” is intended to cover tripping (opening), closing, and reclosing of the circuit breaker.

Most circuit breakers in the United States utilize multiple-pole (three-pole) operation to serve and protect

their entire service area by simultaneous opening or closing of their three poles (phases).

Operating mechanisms are designed to have the closing function in a ready-to-close condition upon

application of a closing signal. Simultaneous with the closing, the tripping function is placed in a readyto-trip condition by electrical, mechanical, or both electrical and mechanical facilities in the operating

mechanism. At the end of the previous closing operation, the closing function is again placed in a readyto-close condition. This interaction of closing and tripping facilities permits any planned number of

sequential closing and tripping actions to be performed.
Bulletin 1724E-300

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The operating mechanism has to perform one complete closing operation including automatic cutoff of

the closing power circuit after the initiating control device has been operated either manually or

automatically and the first seal-in device in the control scheme has responded, even though the contacts of

the initiating control device might be opened before the closing operation has been completed.

Furthermore, a closing operation should not be performed at a control voltage lower than the minimum

control voltage at which successful tripping can be performed. Most circuit breakers use shunt (voltage)

trip coils that have to be capable of tripping the circuit breaker when any voltage in the control voltage

range is applied, even if the trip coil plunger is away from its normal maximum force position to the

extent that it is in contact with the actuating trigger of the tripping system.

Other tripping solenoids include those operated by current from bushing or separate current transformers

and those operated by a capacitor trip device discharge into the trip coil. Refer to Table 5-26 for ac and

dc control, tripping and closing voltages, and voltage ranges.

The operating mechanism should incorporate a number of features specifically for maintenance and

assembly operations. The mechanism has to have provisions that safeguard maintenance personnel from

unintended operation. This is usually accomplished via fuse pullouts, permissive switches, or locking

pins. Provisions are required for slowly closing the breaker to align the moving contacts. This is usually

accomplished with a separate jacking device purchased with the breaker.

Operating mechanisms should be equipped with operation counters. Compressors should be equipped

with elapsed running time meters. These two features are important to an effective maintenance program.

5.3.4.1 Solenoid Operating Mechanisms

5.3.4.1.1 Voltage (AC and DC)-Operated Solenoids: Voltage (ac and dc)-operated solenoids were

used almost entirely on all circuit breakers in the past. They were effective but relatively slow compared

to present operating methods. They also required a large-capacity power supply (transformer or battery)

because of their heavy current (ampere) demand, particularly on large, high-voltage circuit breakers.

Solenoids are still used on some smaller circuit breakers where their lower operating power requirements

are within available limits. Capacitor trip devices can also be provided to operate the solenoid.

5.3.4.1.2 Current-Operated Solenoids: Current-operated solenoids supplied with current from

bushing-type or separate current transformers are available on the smaller circuit breakers and, like the

capacitor trip devices, they are very useful in isolated areas where a separate operating power supply

cannot be justified.

5.3.4.1.3 Other Types: All other types of operating mechanisms (except manual) described below use

small control solenoids of ac or dc operation to initiate the major closing operation performed by the

pneumatic, hydraulic, or spring mechanisms.

5.3.4.2 Motor Operating Mechanisms: Motor operation of circuit breakers, like solenoids, was used

mostly in the past on small circuit breakers and is still available from some suppliers. The motors can be

ac or dc, usually of a high torque and high speed to drive a spring-loaded toggle over dead center and

release to provide good closing speed.

5.3.4.3 Pneumohydraulic : Pneumohydraulic is a coined name for a combination of pneumatic and

hydraulic operating mechanism. An air compressor provides high-pressure air (up to several thousand
Bulletin 1724E-300

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Table 5-26: Rated Control Voltages and Their Ranges for Circuit Breakers. Ref. ANSI/IEEE Std. C37.06-

1997, Table 8. Reproduced with permission of the National Electrical Manufacturers Association.

Operating mechanisms are designed for the rated control voltages listed with operational capability throughout the

indicated voltage ranges to accommodate variations in source regulation, coupled with low charge levels, as well as

high charge levels maintained with floating charges. The maximum voltage is measured at the point of user

connection to the circuit breaker [see notes (12) and (13)] with no operating current flowing, and the minimum voltage

is measured with maximum operating current flowing.

Direct Current Voltage Ranges

(1)(2)(3)(5)

Volts, dc (8)(9)

Closing and Auxiliary

Functions

Rated Control

Voltage

(60 Hz)

Alternating Current

Voltage Ranges

(1)(2)(3)(4)(8)

Closing, Tripping, and

(11) Auxiliary Functions

Rated

Control

Voltage

Indoor

Circuit

Breakers

Outdoor

Circuit

Breakers

Opening

Functions

Line All Types Single-Phase Single-Phase

No. Col 1 Col 2 Col 3 Col 4 Col 5 Col 6

1 24 (6) -- -- 14-28 120 104-127 (7)

2 48 (6) 38-56 36-56 28-56 240 208-254 (7)

3 125 100-140 90-140 70-140

4 250 200-280 180-280 140-280 Polyphase Polyphase

5 208Y/120 180Y/104-

6 220Y/127

7 240 208-254

* Note (10) applies to the entire table.

 See following notes.

Notes for Table 5-26

(1) Electrically operated motors, contactors, solenoids, valves, and the like need not carry a nameplate voltage

rating that corresponds to the control voltage rating shown in the table as long as these components perform

the intended duty cycle (usually intermittent) in the voltage range specified.

(2) Relays, motors, or other auxiliary equipment that functions as a part of the control for a device shall be

subject to the voltage limits imposed by this standard, whether mounted at the device or at a remote

location.

(3) Circuit breaker devices, in some applications, may be exposed to control voltages exceeding those specified

here due to abnormal conditions such as abrupt changes in line loading. Such applications required specific

study, and the manufacturer should be consulted. Also, application of switchgear devices containing solidstate control, exposed continuously to control voltages approaching the upper limits of ranges specified

herein, require specific attention and the manufacturer should be consulted before application is made.

(4) Includes supply for pump or compressor motors. Note that rated voltages for motors and their operating

ranges are covered in ANSI/NEMA MG-1.

(5) It is recommended that the coils of closing, and auxiliary, and tripping devices that are connected continually

to one dc potential should be connected to the negative control bus so as to minimize electrolytic

deterioration.

(6) 24-volt or 48-volt tripping, closing, and auxiliary functions are recommended only when the device is located

near the battery or where special effort is made to ensure the adequacy of conductors between battery and

control terminals. 24-volt closing is not recommended.

(7) Includes heater circuits.

(8) Voltage ranges apply to all closing and auxiliary devices when cold. Breakers utilizing standard auxiliary

relays for control functions may not comply at lower extremes of voltage ranges when relay coils are hot, as

after repeated or continuous operation.

(9) Direct current control voltage sources, such as those derived from rectified alternating current, may contain

sufficient inherent ripple to modify the operation of control devices to the extent that they may not function

over the entire specified voltage ranges.

(10) This table also applies for circuit breakers in gas-insulated substation installations.

(11) In cases where other operational ratings are a function of the specific control voltage applied, tests in

C37.09 may refer to the “Rated Control Voltage.” In these cases, tests shall be performed at the levels in

this column.
Bulletin 1724E-300

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(12) For an outdoor circuit breaker, the point of user connection to the circuit breaker is the secondary terminal

block point at which the wires from the circuit breaker operating mechanism components are connected to

the user’s control circuit wiring.

(13) For an indoor circuit breaker, the point of user connection to the circuit breaker is either the secondary

disconnecting contact (where the control power is connected from the stationary housing to the removable

circuit breaker), or the terminal block in the housing nearest to the secondary disconnection contact.

psi) to a cylinder with a piston used to drive hydraulic fluid into a piping system and servomechanism to

provide closing and tripping operations when the appropriate control signals are applied.

The pneumohydraulic system is an energy storage system, integral with the circuit breaker, and is

required to be of sufficient size to permit at least five complete closing–opening operations at rated shortcircuit current, starting at normal working pressure and without replenishment of the compressed air

energy store. It provides very high speed closing and tripping.

This type of mechanism is normally available, from certain suppliers, on 121 kV and higher rated circuit

breakers.

5.3.4.4 Pneumatic: Pneumatic operating mechanisms utilize compressed high-pressure air (or other

gas) to apply closing and tripping forces directly to the mechanism. A variation of pneumatic operation is

pneumatic closing with a tripping spring being compressed during the pneumatic closing operation. The

pressure varies widely among suppliers from a few hundred to several thousand psi.

Where the pneumatic energy storage is integral with the circuit breakers it has to be of sufficient size to

permit at least two complete closing–opening operations at rated short-circuit current starting at normal

working pressure and without replenishing the compressed air energy store.

Where the pneumatic energy storage is separate from the circuit breaker, it can be designed to any desired

size for any desired combination of operations within the rating structure of the circuit breaker. It can

also be utilized to operate (closing and tripping) several circuit breakers in a similar manner. It has

almost unlimited flexibility for maintenance and emergency piping, valving, backup compressors,

nitrogen bottles, temporary high-pressure hosing, etc.

This type of mechanism is available on most circuit breakers rated 23 kV and higher of the bulk air-blast

and closed-cycle gas-blast types.

5.3.4.5 Motor-Charged Spring: Motor-charged spring operating mechanisms utilize a motor to

compress a coil spring that holds this stored energy until a closing signal is received. Then the spring

expands to close the circuit breaker and simultaneously to charge or compress a smaller coil spring, which

is used to trip the circuit breaker. This trip spring may or may not be concentric with the closing spring,

depending on the individual design. The energy storage capability of a motor-compressed spring

operating mechanism has to be sufficient for an opening–closing–opening operation at rated short-circuit

current, after which the spring-compressing motor should not require more than 10 seconds to compress

the closing spring. Longer times are permissible through agreement between the purchaser and the

manufacturer. In cases where the desired reclosing scheme depends on motor operation, a dc motor may

be specified and supplied from a battery or rectifier.

The above-described breaker mechanism provides high-speed closing and tripping. This type of

mechanism is available on 2.4 kV through 72.5 kV circuit breakers.
Bulletin 1724E-300

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5.3.4.6 Manual-Charged Spring: Manual-charged spring operating mechanisms have very limited

application. They are available only from a few suppliers. Applications where reclosing operation is not

required would be suitable for this type of operating mechanism. Compression of the spring to store the

closing energy is accomplished by a hand jack that may be portable or integral with the operating

mechanism. Energy storage required consists of only one closing and one tripping operation.

5.3.4.7 Manual Operating Mechanisms: Manual operating mechanisms are only available on small

circuit breakers. They utilize a lever-operated toggle mechanism that releases energy from a relatively

small spring. They may or may not have tripping capability. If they cannot trip, a backup protective

device should be applied.

5.3.5 Tests

Tests performed on circuit breakers can generally be classified as follows:

1. Design tests

2. Production tests

3. Tests after delivery

4. Field tests

5. Conformance tests

These tests are fully described in ANSI/IEEE Std. C37.09, “American Standard Test Procedure for AC

High Voltage Circuit Breakers.” While a detailed discussion of these tests is beyond the scope of this

bulletin, a general outline of the tests involved follows.

5.3.5.1 Design Tests: Design tests consist of the following types of tests:

1. Maximum Voltage

2. Voltage Range Factor

3. Continuous Current-Carrying Rated Frequency Tests

4. Dielectric Strength Tests

5. Short-Circuit Tests

a. Symmetrical interrupting capability (polyphase and line-to-line)

b. Assymetrical interrupting capability (polyphase and line-to-line)

c. Interrupting capability for single line-to-ground fault

d. Closing, latching, carrying, and interrupting capability

e. Short-time current carrying capability

f. Reclosing capability

6. Transient Recovery Voltage

7. Standard Operating Duty

8. Tripping Delay

9. Interrupting Time

10. Reclosing Time

11. Load Current Switching Capability

a. Low frequency withstand, dry and wet

b. Full wave impulse withstand

c. Impulse voltage test for interrupters and resistors

d. Chopped wave impulse withstand

e. Switching-impulse voltage withstand

12. Capacitor Switching
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13. Rated Line Closing Switching Surge Factor

14. Out-of-Phase Switching Current

15. Shunt Reactor Switching

16. Excitation Current Switching

17. Mechanical Life

18. Control Voltage Current (Nominal Control Voltage)

5.3.5.2 Production Tests: Production tests are normally made by the manufacturer at the factory as

part of the process of producing the circuit breaker. If the breaker is completely assembled prior to

shipment, some of the production tests are made after final assembly, but other tests can often be made

more effectively on components and subassemblies during or after manufacture.

If the circuit breaker is not completely assembled at the factory prior to shipment, appropriate tests on

components should be made to check the quality of workmanship and uniformity of material used and to

ensure satisfactory performance when properly assembled at its destination. This performance may be

verified by performing tests after delivery.

Production tests and checks include the following:

1. Current and Linear Coupler Transformer Tests

2. Bushing Tests

3. Gas Container Tests (ASME Certification)

4. Pressure Tests

5. Nameplate Check

6. Leakage Tests

7. Resistor, Heater, and Coil Check Tests

8. Control and Secondary Wiring Check Tests

9. Clearance and Mechanical Adjustment Check Tests

10. Mechanical Operation Tests

11. Timing Tests

12. Stored Energy System Tests

13. Conductivity of Current Path Test

14. Low-Frequency Withstand Voltage Tests on Major Insulation Components

15. Low-Frequency Withstand Voltage Tests on Control and Secondary Wiring

5.3.5.3 Tests After Delivery: Tests made by the purchaser after delivery of the circuit breaker to

supplement inspection in determining whether the breaker has arrived in good condition may consist of

timing tests on closing, opening, and close–open, no-load operations, and low-frequency voltage

withstand tests at 75 percent of the rated low-frequency withstand voltage. Polarity and ratio tests on the

current transformers are also recommended.

5.3.5.4 Field Tests: Field tests are made on operating systems usually to investigate the performance

of circuit breakers under conditions that cannot be duplicated in the factory. They usually supplement

factory tests and, therefore, may not provide a complete investigation of the breakers’ capabilities.

Emphasis is usually placed on performance under the particular conditions for which the tests are made

rather than on a broad investigation, and the schedule and instrumentation are adapted accordingly.

Field tests may include transient recovery voltage performance, closing together two energized parts of a

system operating at different levels of voltage and power factor, switching of full-sized shunt reactors or

capacitor banks, contact timing for mechanically linked breaker poles or air supply linked poles where air
Bulletin 1724E-300

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lines may differ in length, measurement of resistances and voltage sharing or division of opening and preinsertion resistors, etc.

5.3.5.5 Conformance Tests: Conformance tests are those tests specifically made to demonstrate the

conformance of a circuit breaker with ANSI Standards.

5.3.6 Control and Auxiliary Power Requirements

Rated control voltages for power circuit breakers in accordance with existing ANSI Std. C37.06 are

shown in Table 5-26.

In addition to the above, it will be necessary to provide auxiliary power at the breaker for use in

conjunction with heater elements, compressor motors, compartment lights, etc. Auxiliary power supplies

are generally available in one of the forms shown in Table 5-26.

5.3.7 Purchase Evaluation

When evaluating different types of breaker construction for a specific substation, it is important to include

the cost of necessary auxiliary equipment such as maintenance jacks, gas handling equipment, oil

handling equipment, tank lifters, etc. Environmental considerations of esthetics, noise, and oil spills may

also affect the choice of breaker type. Others considerations may include size and weight of the breaker,

operating mechanism, lead time, and terms and conditions of the sale.

5.3.8 Shipment and Installation

5.3.8.1 Shipment: Immediately upon receipt, breakers should be examined for any damage en route.

If damage is evident or indication of rough handling is visible, notify the carrier (transportation company)

and the manufacturer promptly.

Method of shipment will be dictated by many things including size of the breaker, destination, urgency of

delivery, etc. In general, the small- to medium (138 to 230 kV)-size oil breakers will be shipped fully

assembled. Most breakers can be shipped either by rail or by truck.

5.3.8.2 Assembly and Installation: Detailed discussion of assembly and installation of circuit

breakers is beyond the scope of this bulletin. However, additional comments can be found in NEMA

Std. SG4, Part 6, “Instructions for the Installation, Operation and Care of Alternating-Current HighVoltage Circuit Breakers.” Manufacturers’ instructions are to be relied upon for the complete and proper

installation of the equipment.

5.3.9 References

ANSI Std. C37.06, “Preferred Ratings and Related Required Capabilities of AC High-Voltage Circuit

Breakers Rated on a Symmetrical Current Basis.”

ANSI Std. C37.12, “American National Standard Guide Specifications for AC High-Voltage Circuit

Breakers Rated on a Symmetrical Current Basis and a Total Current Basis.”

ANSI Std. C84.1, “American National Standard Voltage Ratings for Electrical Power Systems and

Equipment (60 Hz).”
Bulletin 1724E-300

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ANSI Std. C92.2, “Preferred Voltage Ratings for Alternating Current Electrical Systems and Equipment

Operating at Voltages Above 230 Kilovolts Nominal.”

ANSI/IEEE Std. C37.04, “Rating Structure for AC High-Voltage Circuit Breakers Rated on a

Symmetrical Current Basis.”

ANSI/IEEE Std. C37.09, “American Standard Test Procedure for AC High Voltage Circuit Breakers.”

ANSI/IEEE Std. 37.010, “Standard Application Guide for AC High-Voltage Circuit Breakers Rated on a

Symmetrical Current Basis.”

ANSI/IEEE Std. 37.100, “Standard Definitions for Power Switchgear.”

IEEE 1997 Summer Power Meeting, “Loading of Substation Electrical Equipment with Emphasis on

Thermal Capability.”

– Part I – Principles by B.J. Conway, D.W. McMullen, A.J. Peat, and J.M. Scofield of Southern

California Edison Company.

– Part II – Application by I.S. Benko, D.E. Cooper, D.O. Craghead, and P.Q. Nelson of Southern

California Edison Company.

IEEE Tutorial Course Text No. 75CH0975-3-PWR, “Application of Power Circuit Breakers,” 1975.

NEMA Std. SG4, Part 6, “Instruction for the Installation, Operation and Care of Alternating-Current

High-Voltage Circuit Breakers.”

5.4 METAL-CLAD SWITCHGEAR

5.4.1 General

This section deals primarily with metal-clad switchgear for use in distribution substations. Metal-clad

switchgear is defined as a type of metal-enclosed power switchgear with a number of necessary

characteristics. These characteristics are fully defined in IEEE Std. C37.20.2, “Standard for Metal-Clad

and Station-Type Cubicle Switchgear,” Section 2.1.9.3. Briefly, they are as follows:

1. The main switching or interrupting device is removable.

2. Major components of the primary circuit are enclosed and are separated by grounded metal

barriers.

3. All live parts are enclosed within grounded metal compartments with automatic shutters to

block off energized parts when devices are disconnected.

4. The primary bus is covered with insulating material throughout.

5. There are mechanical interlocks for safety and proper operation.

6. Secondary devices are essentially isolated from primary elements.

7. A door to a circuit interrupting device may serve as a control panel or for access to some

secondary elements.

5.4.1.1 Function: Metal-clad switchgear serves the same system function as comparable elements in

a conventional open bus-type substation. These elements may include main power switching or

interrupting devices, disconnecting switches, buses, instrument and control power transformers, and

control and auxiliary devices, as well as other devices.
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Metal-clad switchgear is usually applied where appearance, land use, compactness, ease of installation, exiting

low-voltage circuits, maintenance in foul weather, or safety require consideration. Its application has become

more commonplace to house additional equipment including battery, chargers, low-voltage panels, compact 

microprocessor relaying, and supervisory control equipment as indicated in Figure 5-9. The outdoor single

control house including the switchgear offers a more complete factory-wired and tested assembly. The

advent of the “double-high” breaker configuration in the lower voltage and ampacity cases offers lower costs,

yet requires specific layouts to avoid joint cubicle-forced maintenance outages. The cost difference between

an open substation versus metal-clad switchgear depends on the final installed and operating costs, which will

vary by application and site.

5.4.1.2 Applicable National Standards: The main standards governing metal-clad switchgear are IEEE

Std. C37.20.2, “IEEE Standard for Metal-Clad and Station-Type Cubicle Switchgear,” NEMA Std. SG-5,

“Standards for Power Switchgear Assemblies,” and Std. SG-6, “Standards for Power Switching Equipment.”

The indoor oilless circuit breakers (predominantly equipped with vacuum interrupters and higher voltage SF6

gas interrupting media) are as applied with metal-clad switchgear and rated in accordance with ANSI Std.

C37.06. Additional applicable standards are listed in Section 5.4.5.

5.4.2 Types

5.4.2.1 Configurations: Metal-clad switchgear is available for both indoor and outdoor installations. The

basic switchgear is the same for both types of installations. For outdoor installations, a weatherproof

enclosure is provided. Weatherproof enclosures are made in several arrangements:

• Single-cubicle lineup, without an enclosed aisle

• Single line with enclosed aisle

• Double lineup, with a common enclosed center aisle

Figure 5-10 is a typical outdoor single-aisle arrangement. Variations have been made to extend the housing on

either side of the aisle to use for ancillary equipment and functions. Manufacturers have adopted trade names

for the various arrangements. Shipping splits can be accommodated to allow standard transportation and also

to ease field assembly.

Any decision as to choice of indoor or outdoor type of switchgear should include a cost analysis. Usually

weatherproof enclosures will cost less than indoor units (including the cost of a prefabricated or similar type

of building and the additional labor and ancillary costs). Other factors, of course, may influence the decision

such as joint use of any building for other purposes.

Metal-clad switchgear sections or cubicles are made for every recognized type of switching scheme,

including straight bus (radial circuits), network, sectionalized bus, main and transfer bus, breaker-and-a-half,

ring bus, double bus–double breaker, etc. The level of reliable bus configuration depends on the number of

bus sections, redundant feeders, transformer sources, and alternative external local and remote switching

features. Sections are made or can be adapted for almost any conceivable arrangement of the equipment

usually required in circuits for feeders, transformers, generators, motors, reactors, and capacitors. Entrance

provisions can be adapted to accommodate overhead through-roof bushings with insulated cable or bare bus

bar circuits and non-segregated metal enclosed bus duct. Underground entrances are either by insulated

cable through conduit circuits or wireways. Sections are made to accommodate all sorts of auxiliary

equipment such as current and potential transformers, station power transformers, fuses, switches, surge

arresters, etc.
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Figure 5-9: Single-Aisle Metal-Clad Switchgear with Ancillaries
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Figure 5-10: Typical Single-Aisle Switchgear Installation. 

(Courtesy of Pederson Power Products)
Bulletin 1724E-300

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5.4.2.2 Enclosure Categories: Switchgear assemblies are also installed in locations that vary as to the

degree of access and exposure to the general public. The categories are intended to provide differing degrees

of protection to personnel from coming in contact with the enclosed live parts.

5.4.2.1.1 Category A: This category provides a degree of protection for unauthorized personnel

performing deliberate unauthorized acts on the switchgear lineup.

5.4.2.1.2 Category B: This category provides a degree of protection against contact with the live parts

by untrained personnel and unauthorized personnel, not subject to the deliberate acts of unauthorized

personnel.

5.4.2.1.3 Category C: This category provides a degree of protection against contact with the live parts of

equipment located within secure areas by authorized personnel.

5.4.3 Ratings

5.4.3.1 Rated Nominal Voltage (rms): Rated nominal voltage of a switchgear assembly is the value

assigned for identification. Standard ratings are 4.16, 7.2, 13.8, 25.0, and 34.5 kV. The 25 kV class circuits

are served by either the more costly 34.5 kV class equipment or by some manufacturers’ 25 kV class, which

has now received ANSI Standards recognition.

5.4.3.2 Rated Maximum Voltage (rms): Rated maximum voltage is the highest rms voltage for which

the equipment is designed and is the upper limit for operations. Standard ratings corresponding, respectively,

to the values given in Section 5.4.3.1 above are 4.76, 8.25, 15.0, 27.0, and 38.0 kV. See IEEE Std. C37.20.2,

Table 1.

5.4.3.3 Rated Frequency: Ratings for ac equipment are based on a frequency of 60 Hz.

5.4.3.4 Rated Insulation Levels: Rated insulation levels consist of two items: (1) 60 Hz, one-minute

withstand voltage, and (2) impulse withstand voltage or BIL. The standard values are shown in Table 5-27:

Table 5-27: Rated Insulation Levels of Metal-Clad Switchgear

Rated Nominal Voltage (rms) 60 Hz, 1 Min Withstand BIL

 4.16 kV 19 kV 60 kV

 7.2 kV 36 kV 95 kV

13.8 kV 36 kV 95 kV

25.0 kV 60 kV 125 kV

34.5 kV 80 kV 150 kV

See IEEE Std. C37.20.2, Table 1, for further clarification.

5.4.3.5 Rated Continuous Current: This is the maximum current in rms amperes at rated frequency

that can be carried continuously by the primary circuit components, including buses and connections, without

causing temperatures in excess of specified limits for any component. The standard ratings for the bus are

1200, 2000, and 3000 amperes. The continuous current ratings of the individual units shall correspond to the

ratings of the switching and interrupting devices used.
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5.4.3.6 Rated Short-Time or Momentary Current: This is the maximum rms total current that can be

carried momentarily without electrical, thermal, or mechanical damage. Standard ratings for a bus and its

extensions should be matched to the breaker rated value, which can reach a maximum of 48 kA for 13.8 kV

bus application.

5.4.3.7 Interrupting or Switching Capability: Interrupting or switching capability of a particular device

such as a circuit breaker, interrupter switch, fuse, etc., used in a switchgear assembly is determined by the

rated capabilities of that device as listed in the appropriate standards.

5.4.4 Purchase Considerations

5.4.4.1 Procurement: Metal-clad switchgear assemblies (breaker cells) for a particular job are normally

purchased as a unit (including the breaker) from a single manufacturer because of the standardization and

close coordination required among the various components such as interlocks and connections. The cells can

be joined by either the switchgear breaker manufacturer or an OEM (original equipment manufacturer). Many

qualified U.S. suppliers are widely available that can offer local assistance during and after installation.

5.4.4.2 Specification: Before undertaking a switchgear project, visit various installation sites and

manufacturers’ plants to observe applications and features that would suit the cooperative’s needs. 

Specifications can be supplied by a consulting engineer or drafted based on use of the manufacturer’s

guideline specifications. Any specification for metal-clad switchgear should include the following information

or requirements.

5.4.4.2.1 Switching Scheme Selection and One-Line Diagram: The most common configuration is a single

bus with a main incoming breaker, a tie breaker, and at least four feeder breakers sized to carry 50 percent of

 normal load. The tie circuit allows supply from another transformer and external feeder cross ties to allow

feeder and main breaker removal for maintenance. The choice should be made based on system operating

and reliability requirements and, ultimately, cost. The one-line diagram (somewhat matching the physical

arrangement desired) should indicate bus configuration, ratings, nomenclature, and ancillary equipment

including auxiliary transformers, instrument transformers, surge arresters, number of conductors per circuit,

and entry means.

5.4.4.2.2 Available Fault and Continuous Currents for Breaker Selection: Anything affecting the circuit

breaker requirements should be mentioned such as ultimate source fault capability, parallel transformer

operation and capacity, normal/emergency feeder loading, reclosing duty, operating voltage, capacitor or

reactor switching, etc.

5.4.4.2.3 Main Bus Rating Selection: The predominant bus material used is copper, since it provides

strength and connection advantages over aluminum bus. Standard ratings match the continuous current

rating of available circuit breakers. Judicious arrangements of “source” and “load” breakers can result in the

lowest bus current requirements. Future expansion should be considered. The bus support and conductor

insulation system should be track resistant. The bus insulation should be void free by using either a heatshrink polymer or fluidized bed-applied epoxy. Indicate the bus configuration, whether 3-wire (with neutral

external to the switchgear) or 4-wire (including either reduced or full-size neutral). The neutral bus should

not be confused with mandatory copper ground bus used to bond switchgear cubicles and housing to the

station ground.
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5.4.4.2.4 Current and Potential Transformer Selection: Each transformer should be located on the one-line

diagram and its requirements described. The potential transformers are applied in a wye-wye connection with

a resulting 120/208 V secondary connection that is used commonly for metering and relay potentials. Current

transformers are usually single-ratio type with accuracy ranges from C200 to C400 (see Section 5.10.6) for

most typical applications.

Carefully ground instrument transformer circuits. Separately ground VT primary and secondary circuits to

avoid the tie between the primary and the secondary if the ground is lost. Ground CTs and VTs at one

location on each circuit.

5.4.4.2.5 Relay and Control Function Selection: To ensure that the metal-clad switchgear is wired by the

manufacturer as desired and sufficient space is provided for all equipment, it is vital to detail the types of

relays, control schemes, interlocks, metering, and interconnection features to be incorporated. This usually

involves a cubicle-by-cubicle list of materials to be furnished. It may also include schematic diagrams when

requirements are complex.

5.4.4.2.6 Closing, Tripping, and Power Requirements: For circuit reliability, usually the switchgear is

specified for dc control supply ranging from 48 to 125 volts dc. This control supply may be segmented by

molded case breakers, fuse blocks, or fuse blocks with knife switches in several configurations at the

cooperative’s choice to provide close, open, and breaker motor-spring charging power. Auxiliary power may

be furnished from a fused transformer within the switchgear lineup or externally from a feeder that is not

affected by the switchgear outage. The two most popular auxiliary voltages are 240/120 volts ac, 3-wire,

single-phase, or 120/208 volts ac, 4-wire, three-phase to supply lighting, transformer fan, and LTC control,

battery charging, and switchgear environmental control. The station battery can be supplied with the

switchgear to power the switchgear control supply as well as other station higher voltage breakers.

5.4.4.2.7 Special Requirements of Temperature, Altitude, Unusual Atmospheric Contamination, Vibration,

Etc.: Standard conditions are for operation in air at nameplate ratings within –30°C and +40°C and at altitudes

not exceeding 1000 meters (3300 feet). If a battery bank is housed within the switchgear, it is mandatory to

supply enclosure environmental control by an air conditioner and resistance heating or a heat pump to keep

the battery within its best operating range of from +10°C to +26°C. Airborne dust and other contaminants

may require additional filters and special paint finishes. Address these site-specific conditions depending on

operating experience with other electrical equipment. In most applications, it is necessary to provide either

non-switched or thermostatically controlled long-life resistance heaters to prevent condensation on the bus

insulation and within the breaker during daily and seasonal atmospheric changes.

5.4.4.2.8 Physical Sketch of Desired Arrangement, Orientation, Mounting Requirements, Indoor or

Outdoor Type, Etc.: With a detailed and physically orientated one-line diagram, the manufacturer can usually

submit acceptable arrangements that include cost savings not readily apparent to the cooperative. Plan,

elevation, and cross-section sketches help the manufacturer interpret the specifications for any special

arrangements and the inclusion of ancillaries.

5.4.4.2.9 Itemized List of Requirements: Clearly state in the Bill of Materials all requirements for equipment

in each cubicle and include the number of spare breakers and test equipment to be provided, etc. State

interface points at incoming bus connections, cable external connectors and insulating material, and enclosure

grounding connectors.
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5.4.5 References

ANSI Std. C37.06, “Preferred Ratings and Related Required Capabilities of AC High-Voltage Circuit Breakers

Rated on a Symmetrical Current Basis.”

ANSI/IEEE Std. C37.04, “Standard Rating Structure for AC High-Voltage Circuit Breakers Rated on a

Symmetrical Current Basis.”

IEEE Std. C37.09, “Standard Test Procedure for AC High-Voltage Circuit Breakers Rated on a Symmetrical

Current Basis.”

IEEE Std. C37.010, “Standard Application Guide for AC High-Voltage Circuit Breakers Rated on a

Symmetrical Current Basis.”

IEEE Std. C37.2, “Standard Electrical Power System Device Function Numbers.”

IEEE Std. C37.20.2, “Standard for Metal-Clad and Station-Type Cubicle Switchgear.”

IEEE Std. C37.100, “Standard Definition for Power Switchgear.”

NEMA Std. SG-2, “Standards for High-Voltage Fuses.”

NEMA Std. SG-4, “Standards for Alternating Current High-Voltage Circuit Breakers.”

NEMA Std. SG-5, “Standards for Power Switchgear Assemblies.”

NEMA Std. SG-6, “Standards for Power Switching Equipment.”

5.5 SUBSTATION VOLTAGE REGULATORS

5.5.1 General

Both three-phase and single-phase voltage regulators are used in distribution substations to regulate the loadside voltage. Substation regulators are one of the primary means, along with load-tap-changing power

transformers, shunt capacitors, and distribution line regulators, for maintaining a proper level of voltage at a

customer’s service entrance.

A very important function of substation voltage regulation is to correct for supply voltage variation. With the

proper use of the control settings and line drop compensation, regulators can correct for load variations as

well. A properly applied and controlled voltage regulator not only keeps the voltage at a customer’s service

entrance within approved limits but also minimizes the range of voltage swing between light and heavy load

periods.

The substation regulators may be located on individual feeders or in the transformer secondary circuit for

main bus regulation. Normally, the low-voltage substation bus will be regulated rather than the individual

feeders. Individual feeder regulation can usually be justified only when there are extreme variations between

individual distribution feeder peak load times. Very long or heavily loaded distribution feeders may require

supplemental regulators strategically located out on the line to maintain voltage levels within required limits.
Bulletin 1724E-300

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In evaluating the proper application of voltage regulators, see RUS Bulletin 1724D-114, “Voltage

Regulator Application on Rural Distribution Systems,” and RUS Bulletin 1724D-112, “The Application

of Shunt Capacitors to the Rural Electric System.”

The voltage levels recommended by RUS are given in Bulletin 169-4, “Voltage Levels on Rural

Distribution Systems.” The recommended levels are based on ANSI Std. C84.1, “Voltage Ratings for

Electric Power Systems and Equipment (60 Hz).”

Regulators for use on cooperatives’ systems have to meet the requirements in RUS Bulletin 50-90 (S-2),

“Specification for Substation Regulators,” where applicable. These specifications apply to step-type

single- or three-phase, substation or pole-mounted, outdoor, oil-immersed, self-cooled regulators.

In addition to RUS Bulletin 50-90 (S-2), all regulators should also comply with ANSI Std. C57.15,

“Requirements, Terminology, and Test Code for Step-Voltage and Induction-Voltage Regulators,” and

ANSI Std. C57.95, “Guide for Loading Oil-Immersed Step-Voltage and Induction-Voltage Regulators.”

5.5.2 Types

There are two general types of voltage regulators, the induction regulator and the step-type regulator.

Both types are available in single- or three-phase designs. The step-type regulator has by far the wider

application in the electric distribution system. The step-voltage regulator has virtually replaced the

induction-voltage regulator because it is lower in cost and equally reliable.

5.5.2.1 Step-Type Voltage Regulator: A step-voltage regulator is a regulator having one or more

windings excited from the system circuit or a separate source and one or more windings connected in

series with the system circuit for adjusting the voltage, or the phase relation, or both, in steps, without

interrupting the load. A step-type voltage regulator consists of an autotransformer and a load-tapchanging mechanism built into an integral unit.

As with the induction regulator, when a voltage is impressed on the primary winding, the magnetic flux

linking the secondary or series winding will induce a voltage in the series winding.

An automatic reversing switch is incorporated to obtain an additive or subtractive voltage from the series

winding with respect to the primary voltage. Taps of the series winding are connected to an automatic

tap-changing mechanism to regulate the amount of voltage change in equal steps.

The terminal designations of step-type voltage regulators are as follows:

• The terminal connected to the load is designated L.

• The terminal connected to the source is designated S.

• The common terminal is designated SL.

For three-phase regulators, these identifications are Sl, S2, S3, Ll, L2, L3, and SOLO. This is illustrated in

Figure 3 of RUS Bulletin 1724D-114 and is also found in ANSI C57.15.

5.5.2.2 Single-Phase Versus Three-Phase: Several factors influence the selection. For substation

sizes used most frequently by rural electric systems, single-phase regulators (see Figure 5-11) are usually

less expensive. They also do a better job of maintaining balanced phase voltages under conditions of

unbalanced loading. Single-phase regulators are also more adaptable to line use because of the relative
Bulletin 1724E-300

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ease of pole mounting. Regulation by single-phase regulators also gives maximum reliability for the

system because a regulator can be removed for maintenance or repair without the need to de-energize

transformers or other regulators. Special switches are available to permit removing a regulator from

service without interrupting the circuit. These should always be provided.

In large distribution substations, the choice of three-phase regulators (see Figure 5-12) may be based on

costs or on the availability of single-phase regulators of the required size. Three-phase regulators require

somewhat less space than three single-phase regulators; however, this is not generally a major factor in

selection.

Load-tap-changing power transformers are becoming more common in distribution substations. They

consist essentially of a three-phase regulator built into a three-phase power transformer. The relative cost

of this combination compared to a separate transformer and either three-phase or single-phase regulators

varies depending on the size of the substation.

Aside from the base cost of the equipment, the LTC method generally will result in a saving in space,

buswork, and supporting structures. Because their controls sense only one phase of a three-phase circuit

and since some unbalance may be expected among the phases, the voltage correction of three-phase

regulators and LTC transformers will be less precise than that of single-phase regulators.

Regardless of the selection of single-phase or three-phase regulators, a spare regulator for each substation

is normally not justified.

5.5.3 Ratings

5.5.3.1 kVA Rating: The kVA rating of a single-phase regulator is the product of its rated load

amperes and its rated range of regulation in kilovolts. For polyphase regulators, this product have to be

multiplied by the appropriate phase factors (1.732 for three-phase regulators). The kVA rating of a

10 percent, 7620-volt, single-phase regulator capable of carrying a rated load current of 100 amperes

would be:

kVA = 7.620 x .10 x 100 = 76.2 kVA

In those cases where the range of regulation is different for the “raise” position than for the “lower”

position, the larger percentage regulation is used to determine the regulator kVA rating.

The ratings for regulators generally are based on operation at 60 Hz with a range of regulation of

10 percent “raise” and 10 percent “lower” without exceeding the specified temperature rise at the given

operating voltage. Regulator losses decrease as the regulator moves from the extreme tap positions (boost

or buck) closer to the neutral point. Since the range of regulation required need not always be a full

10 percent, this allows for an extended range of regulator operation.

For the range of regulation of single-phase step regulators rated 19.9 kV and below, see Table 5-28.

For the range of regulation of three-phase, step-voltage regulators rated 13.8 kV and below, see

Table 5-29.
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Figure 5-11: Single-Phase Voltage Regulator (Courtesy of Siemens)
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Figure 5-12: Three-Phase Voltage Regulator (Courtesy of Siemens)
Bulletin 1724E-300

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Table 5-28: Range of Regulation vs. Rated Current for Single-Phase Step Regulators

Rated 19.9 kV and Below. Ref. ANSI/IEEE Std. C57.15-1986, Section 5.4.

Copyright © 1986. IEEE. All rights reserved.

 Range of Voltage Amperes as Percentage

Regulation (Percentage) of Rated Current* 

± 10 100

± 8.75 110

± 7.50 120

± 6.25 135

± 5.00 160

*Maximum current = 668 amperes.

Table 5-29: Range of Regulation vs. Rated Current for Three-Phase Step Regulators

Rated 13.8 kV and Below. Ref. ANSI/IEEE Std. C57.15-1986, Section 5.4.

Copyright © 1986. IEEE. All rights reserved.

 Range of Voltage Amperes as Percentage

Regulation (Percentage) of Rated Current** 

± 10 100

± 8.75 108

± 7.50 115

± 6.25 120

± 6.00 130

**Maximum current = 600 amperes.

It can be seen from Tables 5-28 and 5-29 that if regulators are applied to circuits requiring only 5 percent

regulation, their current-carrying capabilities can be extended to provide additional capacity—up to

160 percent in the case of single-phase regulators.

5.5.3.2 Voltage: Preferred voltage ratings of step-voltage and induction-voltage regulators based on a

voltage range of 10 percent raise and 10 percent lower are given in Tables 5-30 and 5-31.

Substation regulators should be specified as being capable of providing a range of voltage regulation of

±10 percent and a bandwidth not greater than ±1 volt (on a 120-volt base).

Most regulators are specified with a ±10 percent range using thirty-two 5/8 percent steps.

5.5.3.3 Current: Preferred current ratings of oil-immersed step-voltage regulators are listed in

Tables 5-30 and 5-31.

5.5.3.4 Temperature: ANSI Standard ratings of kVA, voltage, and current for air-cooled voltage

regulators are based on ambient air temperature not exceeding 40oC and on the average temperature of the

cooling air for any 24-hour period not exceeding 30oC. For loading under other conditions, see ANSI

Std. C57.95, “Guide for Loading Oil-Immersed Step-Voltage and Induction-Voltage Regulators.”

The ratings are based on a temperature rise above the ambient in accordance with Table 5-32.
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Table 5-30: Preferred Ratings for Oil-Immersed Step-Voltage Regulators

(Single-Phase). Ref. ANSI/IEEE Std. C57.15-1986, Table 3.

Copyright © 1986. IEEE. All rights reserved.

Nominal

System

Voltage BIL (kV) kVA Line Amperes

2400/4160Y 60 50 200

 75 300

100 400

125 500

167 668

250 1000

333 1332

4800/8320Y 75 50 100

 75 150

100 200

125 250

167 334

250 500

333 668

7620-13 200Y 95 38.1 50

 57.2 75

 76.2 100

 114.3 150

167 219

250 328

333 438

416 546

509 668

667 875

833 1093

13 800 95 69 50

138 100

207 150

276 200

414 300

552 400

14 400/24 940Y 150* 72 50

144 100

216 150

288 200

333 231

432 300

576 400

667 463

833 578

19 920-34 500Y 150* 100 50

200 100

333 167

400 201

667 334

833 418

*Low-frequency test voltage 50 kV by induced test with neutral grounded.
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Table 5-31: Preferred Ratings for Oil-Immersed Step-Voltage Regulators

(Three-Phase). Ref. ANSI/IEEE Std. C57.15-1986, Table 4.

Copyright © 1986. IEEE. All rights reserved.

Nominal Self-Cooled Self-Cooled/Force Cooled

System Voltage

BIL

(kV) kVA Line Amperes kVA Line Amperes

2400 45

 500

 750

1000

1155

1732

2309

 625

 937

1250

1443

2165

2887

2400/4160Y 60

 500

 750

1000

 667

1000

1334

 625

 967

1250

 833

1250

1667

4800 60

 500

 750

1000

 577

 866

1155

 625

 937

1250

 721

1082

1443

7620/13 200 95

 500

 750

1000

1500

2000

 219

 328

 437

 656

 874

 625

 938

1250

2000

2667

 274

 410

 546

 874

1166

7970/13 800Y 95

 500

 750

1000

1500

2000

2500

 209

 313

 418

 628

 837

1046

 625

 937

1250

2000

2667

3333

 261

 391

 523

 837

1116

1394

14 400/24 940Y 150

 500

 750

1000

1500

2000

2500

125.5

188.3

 251

 377

 502

 628

 625

 937

1250

2000

2667

3333

 156.8

 235.4

 314

 502

 669

 837

19 920/34 500Y 150

 500

 750

1000

1500

2000

2500

 83.7

 125.5

 167

 251

 335

 418

 625

 937

1250

2000

2667

3333

 104.6

 156.8

 209

 335

 447

 557

26 560/46 000Y 250

 500

 750

1000

1500

2000

2500

 62.8

 94.1

 126

 188

 251

 314

 625

 937

1250

2000

2667

3333

 78.5

 117.6

 157

 251

 335

 419

39 840-69 000Y 350

 500

 750

1000

1500

2000

2500

 41.8

 62.8

 83.7

 126

 167

 209

 625

 937

1250

2000

2667

3333

 52.5

 78.5

 105

 167

 223

 278
Bulletin 1724E-300

Page 260

Table 5-32: Limits of Temperature Rise. Ref. ANSI/IEEE Std. C57.15-1986, Table 2.

Copyright © 1986. IEEE. All rights reserved.

Item Type of Apparatus*

Winding

Temperature

Rise by

Resistance, oC

Hottest-Spot Winding

Temperature Rise, oC

(1) 55oC Rise Liquid-Immersed

55oC Rise Dry-Type

80 oC Rise Dry-Type

150 oC Rise Dry-Type

55

55

80

150

65

65

110

180

(2) Metallic parts in contact with or adjacent to the insulation shall not attain

a temperature in excess of that allowed for the hottest spot of the

windings adjacent to that insulation.

(3) Metallic parts other than those covered in Item (2) shall not attain

excessive temperature rises.

(4) Where a regulator is provided with sealed-tank, conservator, gas-oilseal, or inert-gas-pressure systems, the temperature rise of the

insulating oil shall not exceed 55oC when measured near the surface of

the oil. The temperature rise of insulating oil in a regulator not provided

with the oil preservation systems listed above shall not exceed 50oC

when measured near the exposed surface of the oil.

* Apparatus with specified temperature rise shall have an insulation system that has been proved by

experience, general acceptance or accepted test.

NOTE: In the context of Item 1, dry-type apparatus is understood to refer to induction-voltage regulators.

5.5.3.5 Altitude: ANSI Standard ratings of voltage regulators are based on an altitude not exceeding

1000 meters (3300 feet). At higher altitudes, the decreased air density has an adverse effect on the

temperature rise and the dielectric strength of voltage regulators. Table 5-33 gives correction factors for

dielectric strength at altitudes above 1000 meters.

Table 5-33: Dielectric Strength Correction Factors for

Altitudes Greater Than 3,300 Feet (1,000 Meters)

Ref. ANSI/IEEE Std. C57.15-1986, Table 1.

Copyright © 1986. IEEE. All rights reserved.

Altitude

Correction

Altitude Factor for

Feet Meters Dielectric

Strength

 3,300 1,000 1.00

 4,000 1,200 0.98

 5,000 1,500 0.95

 6,000 1,800 0.92

 7,000 2,100 0.89

 8,000 2,400 0.86

 9,000 2,700 0.83

10,000 3,000 0.80

12,000 3,600 0.75

14,000 4,200 0.70

15,000 4,500 0.67

NOTE: Altitude of 15,000 feet is considered a maximum for standard regulators.
Bulletin 1724E-300

Page 261

Table 5-34 gives a basis for loading above 1000 meters. Also, see ANSI Std. C57.95, “Guide for Loading

Oil-Immersed Step-Voltage and Induction-Voltage Regulators.”

Table 5-34: Reduction Factors for Altitudes

Greater Than 1000 m (3300 ft). Ref. ANSI/IEEE Std. C57.95-1984, Table 2.

Copyright © 1984. IEEE. All rights reserved.

Types of Cooling

Reduction Factor

for Each 100 m

Above 1000 m (%)

Liquid-immersed, self-cooled 0.4

Liquid-immersed, forced-air-cooled 0.5

1000 m (3300 ft), with an ambient temperature of 30°C.

NOTE: See ANSI/IEEE Std. C57.15-1986 [2], 4.3.2, for regulator insulation capability at altitudes

above 1000 m (3300 ft).

5.5.3.6 Short-Circuit Strength: Regulators used on cooperatives’ systems have to be capable of

withstanding rms symmetrical short-circuit currents of 25 times the regulator full-load current for

2 seconds and 40 times the regulator full-load current for 0.8 seconds without injury.

Where short-circuit duty on the regulator exceeds its capabilities, current-limiting reactors may be

installed in the substation to limit the available fault current.

5.5.4 Regulator Controls

5.5.4.1 General: Regulators are equipped with a number of devices and controls that allow the

operator to use the regulator effectively. These include means for setting or adjusting the voltage level,

bandwidth, time delay, range of regulation, and line drop compensation.

Since a change in the setting of any one of these devices will directly affect the operation of one or more

of the other devices, they are all treated as a unit comprising what is known as the regulator control

system. In earlier regulators, the components of this control system were electromechanical, but

regulators manufactured since about 1963 are equipped with static-type devices featuring solid-state or

microprocessor components. The setting of the individual devices in the newer control systems is based

on the same principles. They are, in general, easier to set than the older mechanical type.

The various devices used in the control system are almost all adjusted at the control panel. One exception

is the range of regulation, which is made at the position indicator mounted on the regulator. The control

panel can be mounted directly on the regulator or remote from the regulator.

Microprocessor controls are available with many different options. These options include power and

energy metering, harmonics analysis, event logging, and communication packages.

For a brief description of the control devices and the settings recommended by RUS, see Bulletin 1724D114.

5.5.4.2 Control System Accuracy: The individual components utilized in the regulator control

system are accurate devices and, as such, they enable the regulator to obtain a level of efficiency

sufficient to meet Class I accuracy requirements. Class I accuracy means that the sum of errors in the
Bulletin 1724E-300

Page 262

control circuit taken individually cannot total more than ±1 percent. A plus error would be one causing

the regulator output to be higher than the reference value, while a minus error would be one causing the

regulator output to be lower than the reference value.

Because of this accuracy and, more importantly, because of its function in maintaining system voltage

levels, the voltmeters and other instruments used in conjunction with regulators should be as accurate as

the regulator. To utilize measuring equipment any less efficient than this deprives the system of the

regulator’s full capabilities.

5.5.5 Lightning Protection

Voltage regulators, like other elements of the distribution system, require protection from lightning and

other high-voltage surges. Because voltage regulators are constructed like autotransformers, having one

of the windings in series with the primary line, additional protection is required for this series winding.

Regulators are normally factory equipped with bypass arresters across this series winding; these arresters

may be connected internally or externally, depending on the manufacturer. The bypass arrester limits the

voltage developed across the series winding during surges to within safe values.

CAUTION: Bypass arresters protect only the series winding of the regulator

and do not eliminate the need for arresters to protect the regulator itself.

5.5.6 References

ANSI Std. C57.15, “Requirements, Terminology, and Test Code for Step-Voltage and Induction-Voltage

Regulators.”

ANSI Std. C57.95, “Guide for Loading Oil-Immersed Step-Voltage and Induction-Voltage Regulators.”

ANSI Std. C84.1, “Voltage Ratings for Electric Power Systems and Equipment (60 Hz).”

RUS Bulletin 1724D-112, “The Application of Shunt Capacitors to the Rural Electric System.”

RUS Bulletin 169-4, “Voltage Levels on Rural Distribution Systems.”

RUS Bulletin 1724D-114, “Voltage Regulator Application on Rural Distribution Systems.”

RUS Bulletin 50-90 (S-2), “Specification for Substation Regulators.”

5.6 SHUNT CAPACITOR EQUIPMENT

5.6.1 General

Shunt capacitor banks at substations improve power factor and voltage conditions by supplying leading

kilovars to transmission and distribution systems. For the criteria to determine the need for capacitors and

selecting size, location, etc., refer to RUS Bulletin 1724D-112, “The Application of Shunt Capacitors to

the Rural Electric System.”

IEEE Std. 1036, “IEEE Guide for Applications of Shunt Power Capacitors,” provides guidelines for the

application, protection, and ratings of equipment for the safe and reliable utilization of shunt power
Bulletin 1724E-300

Page 263

capacitors. NEMA Std. CP-1, “Standards Publication—Shunt Capacitors,” also provides guidelines for

the application of shunt capacitors.

Consult RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification

Borrowers,” for accepted manufacturers’ types of individual capacitor units.

5.6.2 System Considerations

5.6.2.1 General: Evaluate system issues, including the effects of switching transients and potential

harmonic resonance, with each bank installation. Shunt capacitor banks alter an electrical system’s

response to disturbances, which can impair system performance.

Specific issues that designers should consider include transients caused by bank energization and

potential resonance conditions.

5.6.2.2 Switching Transients

5.6.2.2.1 Bank Energization: Transient voltages and currents occur whenever shunt capacitor banks

are energized. Overvoltages can reach twice the system voltage, with inrush currents ranging from 5 to

15 times normal steady-state current. Transient magnitude and duration depend on the natural damping

provided by the circuit’s resistive elements. Transient voltages and current resulting from capacitor

switching have to be controlled to avoid exceeding equipment capabilities and damaging customers’

sensitive electronic equipment.

ANSI/IEEE Std. C37.012, “IEEE Application Guide for Capacitance Current Switching for AC HighVoltage Generator Circuit Breakers Rated on a Symmetrical Current Basis,” provides guidelines for

calculating transient inrush and discharge currents. It is important that the design engineer calculate the

peak magnitude and frequency of these transient currents to compare to the capabilities of the shunt

capacitor bank’s equipment and adjoining substation equipment.

5.6.2.2.1.1 Isolated Bank Switching: The transient inrush current to a single isolated bank is less than

the available short-circuit current at the capacitor location. Since a circuit breaker has to meet the

momentary current requirement of the system, transient inrush current is not a limiting factor for this

application. However, the momentary rating of other switching devices not intended for fault current

interruption should be checked.

5.6.2.2.1.2 Back-to-Back Switching: Figure 5-13 illustrates a typical arrangement for two capacitor

banks switched back to back. Capacitor banks switched back to back (one being energized when another

is already connected to the same bus) produce transient currents of high magnitude and high frequency

that flow between the banks on closing of the switching device. The oscillatory current is limited only by

the impedance of the capacitor banks and the circuit between them and usually decays to zero in a fraction

of a cycle of the power frequency. The component supplied by the power source is usually so small it

may be neglected.

Additional impedance between capacitor banks may be required in the form of inductors to allow for

back-to-back switching. (See Section 5.6.2.2.4.)

5.6.2.2.1.3 Induced Voltage: The magnetic fields associated with high inrush current during

energization of shunt capacitor banks (isolated bank or back-to-back switching) in either the overhead
Bulletin 1724E-300

Page 264

Figure 5-13: Typical Capacitor Bank—Two Three-Phase Capacitor Racks Connected

to Form a Two-Step Bank, Floating Wye with a Common Neutral

conductors or the grounding grid can induce voltages in control cables by both electrostatic and

electromagnetic coupling. These induced voltages can be minimized by shielding the cables, using a

radial configuration for circuits (circuits completely contained within one cable so inductive loops are not

formed), and single-point or peninsula grounding of the capacitor banks. (See ANSI/IEEE Std. C37.99,

“IEEE Guide for the Protection of Shunt Capacitor Banks,” for definitions of these types of grounding

configurations.)
Bulletin 1724E-300

Page 265

5.6.2.2.1.4 Voltage Amplification: Applying capacitor banks at more than one voltage level in an

interconnected system can result in voltage amplification that can cause nuisance tripping of adjustablespeed drives, damage to surge suppressors on low-voltage equipment, and, possibly, adverse effects to

sensitive electronic equipment.

Voltage amplification occurs when switching transients, initiated by capacitors located on primary

systems, become amplified at capacitors located on secondary systems. The reason is that the frequency

of the transient initiated by the primary system capacitor approximates the resonant frequency of the

circuit formed by the step-down transformer located in series with secondary system capacitors.

5.6.2.2.2 Control of Switching Transients: The magnitude of switching transients caused by capacitor

bank switching may be greatly reduced by adding current-limiting reactance in series with the bank or

through application of transient control switching devices.

5.6.2.2.1.1 Transient Control Switching Devices: Transient-control switching devices limit the

effects of capacitor switching. Three common methods are used:

1. Fitting circuit switchers with pre-insertion inductors

2. Adding pre-insertion resistors to circuit breakers

3. Incorporating vacuum switches with synchronous closing control

The first two methods momentarily insert an impedance electrically in series with the capacitor bank

when it is energized, dampening transient voltages to acceptable levels. The third method, synchronous

closing, attempts to energize each phase of a three-phase capacitor bank at the instant the applied voltage

crosses zero. This is achieved through synchronous control of the bank’s independent pole vacuum

switches.

Theoretically, “zero-voltage control” eliminates switching transients. However, experience shows this

technique only lowers switching transients because the switching device’s electrical and mechanical

tolerances provide only near-zero-voltage closing.

5.6.2.2.3 Bank De-Energization: Capacitive switching devices have to be capable of providing

sufficient dielectric recovery when interrupting capacitive current or the current arc will ignite or

“restrike.” A single restrike results in a transient voltage three times system voltage.

Modern capacitor switching devices rarely restrike. However, use caution to ensure shunt capacitors do

not inadvertently de-energize through operation of upline circuit breakers because an underrated circuit

breaker could potentially cause restrike. Voltage transients initiated by restrike have been known to cause

catastrophic capacitor bank failures.

5.6.2.2.4 Current-Limiting Reactance: It may be necessary to provide inductive reactance in the form

of current-limiting reactors to limit inrush current during capacitor bank switching.

Sometimes adequate impedance to limit the inrush current to the rating of the switch may be obtained by

physically locating the banks as far apart from one another in the substation as possible. In other cases, it

may be necessary to provide inductive reactance in the form of current-limiting reactors between parallel

switched capacitor banks.

To limit the peak inrush current to “kA” in a substation of “n” equal-size parallel capacitor banks, of
Bulletin 1724E-300

Page 266

“MVAR” megavars per phase each at “f” hertz, provide a current-limiting reactor in each phase of each

bank of “LT” microhenries per phase, according to Equation 5-4:

Equation 5-4

Where:

LT = Required inductance, μH

MVAR = Megavars per phase at 60 Hz

n = Number of parallel banks

f = Frequency, Hz

kA = Maximum allowable inrush current, kA

ð = 3.1416

Example 5-1 shows a typical inrush current calculation for back-to-back switching involving

Equation 5-4.

Example 5-1

Typical Inrush Current Calculations—Back-to-Back Switching

Two capacitor banks, each 13,500 kVAR, 14,400 volt, 60 Hz, both switched by 15 kV vacuum switches,

rated for 20,000-ampere momentary peak:

Where:

MVAR = 13 − 5/3 ≥ 4.5

n = 2

kA = 20

f = 60

ð = 3.1416

For this case, the equipment design would probably specify a 30 μH, 600-ampere reactor in each phase of

each bank.

In determining the continuous current rating of the reactor, the increase in current due to applied voltage,

capacitance tolerance, and harmonics should be considered. As discussed in Section 5.6.6.1, it is

considered adequate to use a total multiplier of 1.25 and 1.35 for ungrounded and grounded banks,

respectively. Assuming that the banks are ungrounded, the minimum continuous rating for each reactor

would be:

If the capacitor manufacturer determines and supplies all accessory equipment, including switches and

reactors, it is necessary to inform the manufacturer of the total MVAR in the substation, the inductive

(kA) f n

MVAR 10 (n -1) L 2

6

T

⋅π ⋅ ⋅

⋅ ⋅

=

( )

29.8 H

20 60 2

4.5 10 2 -1

L 2

6

T = μ

× π × ×

× ×

=

( ) ( ) x 1000 676 amps

14.4 3

4.5 3

 1.25

kV 3

kVAR I 1.25

2

1

2

1

=

×

×

=

×

=
Bulletin 1724E-300

Page 267

reactance of the bus between the capacitor banks, and system available fault current. This will allow the

manufacturer to calculate the ratings of any required reactors. When physically locating these reactors,

take care to space them as far apart as practical to minimize the effect of mutual reactance. The reactors’

continuous current ratings should be at least equal to the continuous current ratings of the switches they

protect and should meet the requirements of IEEE Std. C57.16, “IEEE Standard Requirements,

Terminology, and Test Code for Dry-Type Air-Core Series-Connected Reactors.”

5.6.2.3 Resonance: Resonance occurs whenever an electrical circuit’s inductive and capacitive

reactances—connected either in parallel or series—are equal at some frequency. A shunt capacitor bank

forms a resonant circuit with system inductive elements. This resonance condition can be excited by

remote system disturbances such as remote bank switching or sources of harmonic current. Resonance

can cause excessive overvoltages and currents possibly resulting in failure of equipment such as

capacitors, surge arresters, instrument transformers, and fuses.

5.6.2.4 Harmonic Resonance: Capacitor banks may resonate with harmonic currents produced

elsewhere on the system. Harmonic-current flow into the capacitor bank may excite parallel resonance

between the system inductance and bank capacitance. Parallel resonance causes high oscillating currents

between inductive and capacitive energy-storage elements. High oscillating currents cause excessive

voltage distortion.

Installing current-limiting reactors in series with the shunt capacitor bank can “tune” the bank to the

offending harmonic’s frequency and eliminate parallel resonance. Essentially, a single-tuned filter is

formed by the bank’s resistive, inductive, and capacitive elements. The bank traps harmonic current to

which it is tuned. Parallel resonance is avoided since harmonic current cannot flow between the system

inductance and the bank’s capacitance.

IEEE Std. 519, “IEEE Recommended Practices and Requirements for Harmonic Control in Electrical

Systems,” suggests acceptable harmonic-current levels industrial users can inject into supplying utility

systems and the quality of voltage that the utility should supply.

5.6.3 Types

Shunt capacitor bank designs include open-rack and metal-enclosed bank designs. Open-rack substation

capacitor banks are used to provide large blocks of kilovars on distribution and transmission systems at

voltages up to 765 kV. Metal-enclosed substation capacitor banks are used to apply medium-size blocks

of kilovars on distribution systems up to 34.5 kV where a completely enclosed assembly is advantageous

for space or safety reasons.

5.6.3.1 Open-Rack Substation Capacitor Bank: This type of capacitor bank design mounts capacitor

units vertically or horizontally in aluminum or galvanized steel frames. Ancillary devices including

switching equipment, instrument transformers, and surge protection are mounted on separate structures.

This type of capacitor bank can be furnished with all phases in a single rack or with only one phase in a

single rack. The largest standard “upright” rack usually holds 40 capacitor units, and the largest “edgemount” rack usually 32 units. These racks are generally furnished complete with individual capacitor

units, unit fuses, insulators, supporting structure, and other equipment necessary for a complete

installation.

Open-rack capacitor banks have many exposed, live components and have to be enclosed with a fence. A

key interlock system can be used to prevent entry into the enclosure until capacitors are properly
Bulletin 1724E-300

Page 268

grounded. This bank design is susceptible to rodent-related failures since chain-link fences do not keep

out all rodents. Additionally, adequate electrical clearances have to be provided for exposed live parts

and external expulsion fuses, which results in a large footprint for most open-rack capacitor banks.

For most substation applications in open racks, individual capacitor units are equipped with only one

bushing. The second bushing is often unnecessary when the racks themselves form a part of the circuit

and are insulated by means of base insulators. In a three-phase delta-connected rack, however, two

bushing units are required.

Open-rack capacitor banks use capacitor units that are protected through external fuses.

5.6.3.2 Metal-Enclosed Substation Capacitor Bank: This type of capacitor bank design completely

encloses the bank’s components within a grounded structure, which eliminates the need for a fenced

enclosure and mitigates rodent problems. Enclosed capacitor banks are more aesthetically pleasing

compared to open-rack capacitor banks. The capacitor bank assembly is generally furnished with

internally fused capacitor units, insulators, current-limiting reactors, vacuum switches, grounding

switches, main line fusing, line disconnect switches, surge arresters, instrument transformers, protection,

monitoring and control devices, and a cable entrance section. The doors of the enclosure are key

interlocked to prevent entry into a live compartment.

Enclosed capacitor banks generally use internally fused capacitor units that are compact in design and

more reliable compared to externally fused capacitor units.

Enclosed capacitor banks can be completely pre-assembled and shipped to a project site.

5.6.4 Bank Configuration

A capacitor bank of a given size and voltage rating may be made up of a number of series and parallel

groups. Use of capacitors with the highest possible voltage rating results in a bank design with the fewest

number of series groups, which provides for the most economical design and greatest sensitivity for

unbalance detection schemes.

The maximum and minimum number of capacitor units in parallel per series group is limited by capacitor

unit design considerations regarding permissible overvoltages and avoidance of case rupture. It is

important in any capacitor installation to ensure that the maximum operating voltages do not exceed

110 percent of the rated voltage of any capacitor. Because of this, the number of parallel capacitor units

in each series section is selected so that the loss of any one unit in any series section will not result in

such overvoltage. Additionally, steady-state voltage rises introduced by the flow of harmonic currents

into tuned shunt capacitor banks (banks fitted with current-limiting reactors) have to be considered.

ANSI/IEEE Std. C37.99 provides recommendations for the maximum and minimum number of parallel

capacitor units per series group.

Where only one series section of paralleled capacitors per phase is used and connected either three-phase

grounded wye or delta, the unit capacitor fuse is subjected to full system short-circuit available current

when its associated unit fails. This generally requires that more expensive, high-interrupting-capacity,

current-limiting fuses be applied in situations where available fault currents exceed 4 kA. One advantage

is that these banks can be designed in very small sizes without encountering unacceptable overvoltages on

the remaining capacitors in a phase when one or more capacitors in that phase fails and clears, which
Bulletin 1724E-300

Page 269

simplifies the protection scheme. For open-rack designs, the racks themselves do not have to be insulated

from ground, thus saving the cost of base insulators.

When a three-phase wye connection is used with only one series section of paralleled units per phase, it is

advantageous from a fusing standpoint to leave the neutral floating. This allows the unfaulted phases to

limit the fault current supplied to the faulted phase. The fuse on the faulted unit will “see” a maximum of

only three times normal bank phase current. While this may still be considerable current for large

equipment, it is far less than usually available from the system, and a much less expensive, lowinterrupting-capacity fuse can be applied. A (low) calculated risk is taken of simultaneous failure of units

in different phases. It should be noted that, in a floating wye connection, the neutral has to have full line

insulation between it and ground as well as sufficient ground clearances.

A double-wye configuration is often used where large amounts of kVAR are desired and the equipment is

to be equipped with low-interrupting-capacity expulsion fuses. Designing this bank with connected

multiple series groups limits the maximum fault current so that individual current-limiting capacitor fuses

are not usually required unless the parallel kVAR exceeds 4,650 kVAR, in accordance with ANSI/IEEE

Std. C37.99. Double-wye banks with only single series groups do not limit the maximum fault current.

Therefore, individual capacitor fuses have to be capable of interrupting the system available fault current.

Figure 5-14 illustrates a typical Y-Y connected capacitor bank with one series section per phase and

neutrals isolated.

Delta-connected capacitor banks are generally applied only on lower voltage (23 kV or below) systems

where the system voltage equals the voltage rating of a unit capacitor. They have to also be properly

insulated from ground. Additionally, where one series group per phase is used, individual capacitor unit

fuses should be capable of interrupting the system short-circuit phase-to-phase fault current. This usually

requires the use of current-limiting fuses.

5.6.5 Ratings

5.6.5.1 Circuit Voltage: Domestic manufacturers can supply individual capacitor units in voltages

ranging from 2.4 to 25 kV. Units of the same or of different voltage ratings can be mixed to obtain the

required circuit voltage. Most cooperatives utilize capacitor equipment at or above 7.2 kV.

The desired circuit voltage is obtained by connecting as many capacitor groups in series as necessary to

obtain the required voltage. Usually, the best engineering choice is to use the fewest number of series

groups as possible. Use of capacitors with the highest possible voltage rating results in fewer series

groups. This generally provides the simplest and most economical bank design. However, inventory or

other economic considerations may override this rule.

5.6.5.2 kVAR Rating: Capacitor unit ratings available from domestic manufacturers undergo frequent

change in order to provide the most practical and economical sizes for existing conditions. In general, the

trend is toward larger unit sizes. Standard capacitor units for shunt capacitor bank applications are 50,

100, 150, 200, 300, and 400 kVAR. No upper limits are defined for internally fused capacitor units.

These units are typically sized based on minimizing the number of capacitor units to minimize the bank’s

physical size while avoiding overvoltage and unbalance conditions with a substantial loss of a capacitor

unit’s individually fused elements.
Bulletin 1724E-300

Page 270

Figure 5-14: A Y-Y Connected Capacitor Bank with One Series Section per Phase and Neutrals Isolated

The capacitor manufacturer’s recommendations should be considered in determining the optimum size of

capacitor unit, number of series sections, number of units in parallel, and type of connection to make up

the kVAR requirement for a given application.

5.6.5.3 Basic Insulation Level: Basic impulse insulation levels of individual capacitor units range

from 75 to 200 kV. Table 5-35 summarizes typical basic impulse insulation levels by capacitor unit

voltage rating.

5.6.5.4 Temperature: The maximum allowable ambient temperature for capacitor equipment installed

outdoors with unrestricted ventilation is 40°C (104°F) based on the mathematical average of hourly

readings during the hottest day expected at the site. Isolated, multiple row and tiers and metal-enclosed or

B

A

C

("N") UNITS IN PARALLEL

"K" KVAR, "V" VOLTS EACH

RACK

FUSE "I" AMP.

"V" VOLTS 

N1 N2
Bulletin 1724E-300

Page 271

Table 5-35: Capacitor Unit Voltage and BIL Ratings. Ref. IEEE Std. 1036-1992.

Based on Table 3. Copyright © 1992. IEEE. All rights reserved.

Capacitor Voltage Rating

(Volts, rms)

BIL

(kilovolts)

2,400 – 4,800 75

6,640 – 12,470 95

13,280 – 14,400 95 and 125

15,125 – 19,920 125

19,920* 125 and 150

19,920 – 24,940* 150 and 200

* Single bushing units only.

housed units will have maximum ambient ratings of 46°C, 40°C, and 40°C, respectively. Capacitors are

designed for continuous operation at –40°C (–40°F). Where the expected in-service ambient

temperatures are lower than –40°C, the manufacturer should be consulted.

5.6.6 Switching

5.6.6.1 Switching Devices: The various devices that may be used for capacitor switching include those

listed in Table 5-36.

Table 5-36: Switching Devices

Circuit Breakers Interrupter Switches

Air Oil

Air-Magnetic SF6

Oil Vacuum

SF6

Vacuum

When a capacitor bank is energized or de-energized, current and voltage transients are produced that

affect the capacitor bank on the connected system. All capacitor switching devices should be applied

within their maximum voltage, frequency, and current ratings, including transient inrush current and

frequency.

The switching device should have a voltage rating at least equal to 10 percent above rated capacitor

voltage since capacitors can be continuously operated at this voltage.

Select the switching device’s continuous current rating based on consideration of factors that increase

current flow in the capacitor bank. Multiplying factors are generally applied to include the effects of

overvoltage (1.10), capacitor tolerance (1.05 to 1.15), and harmonic component (1.05 for ungrounded

capacitor banks: 1.10 for grounded capacitor banks). It is usually considered adequate to use a total

multiplier of 1.25 for ungrounded operation and 1.35 for grounded operation. (See ANSI/IEEE

Std. C37.99.)

It is important to understand that most switching devices are derated for capacitor switching. A switching

device’s rated capacitance switching capability is usually well below the device’s continuous current

rating.

It is important to select a switching device designed for the application’s specific duty to avoid

potentially damaging overvoltages.
Bulletin 1724E-300

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ANSI/IEEE Std. C37.04, “IEEE Standard Rating Structure for AC High-Voltage Circuit Breakers Rated

on a Symmetrical Current Basis”; ANSI Std. C37.06, “American National Standard for Switchgear—AC

High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis—Preferred Ratings and Related

Required Capabilities”; and ANSI/IEEE Std. C37.012, “IEEE Application Guide for Capacitance Current

Switching for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis,” provide rating

and application information for switching devices.

5.6.6.2 Controls: Controls for capacitor switching devices may operate in response to various signals

such as voltage, current, VAR, temperature, time, or some combination of these. A variety of options is

available in terms of price, features, and quality. These range from high-priced panel-mounted to lowpriced socket-mounted controls. In recent years, capacitor controls based on electromechanical relays

have been superseded by more modern electronic types including solid-state and microprocessor-based

controllers. See Figures 5-15 through 5-18 for typical schematics of various capacitor control

arrangements.

Control and application of capacitors are such closely related subjects that a discussion of one has to

necessarily involve the other. In fact, in the typical situation, both the type of control and its adjustment

are dictated by the objectives of the capacitor installation.

Capacitor switching controls provide outputs that are basically single-pole, double-throw switches

activated by control signal(s) selected to reflect kVAR requirements. Theoretically, at least, any

intelligence that changes only when a change in the kVAR supply is needed can be utilized to switch

capacitors automatically. In practice, however, selecting a signal that accurately reflects the requirements

of the system often turns out to be the most difficult part of the problem. The single-input types, such as

voltage and time controls, are generally less expensive in initial cost and installation, less complex, and

easier to adjust but less flexible in application than the dual-input types such as kilovar and current-biased

voltage controls.

The selection of a control for a particular switched capacitor bank requires careful evaluation of several

related factors. Some of the more important considerations are listed below. No attempt has been made

to list them in any particular order, since their relative importance and probably even the factors

themselves will vary considerably from one system to another.

• Purpose—The purpose of the bank affects selection of the appropriate controller. The purpose

may be to reduce losses, improve voltage under normal or emergency operating conditions,

reduce thermal loading of lines and equipment, etc.

• Location—The location of the bank affects what control parameter best represents changes in

kVAR requirements. The bank’s location influences whether voltage will drop appreciably as

load increases, whether direction of feed is likely to change frequently because of normal or

emergency circuit rearrangements, etc.

• Coordination—Coordination with related supplementary voltage regulation equipment

including switched capacitors and voltage regulators affects the type of control strategy to be

implemented.
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Figure 5-15: Typical Capacitor Bank Grd Wye Connected
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Figure 5-16: Typical Capacitor Bank Floating Wye
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Figure 5-17: Typical Capacitor Bank Wye Wye Connected
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Figure 5-18: A Complete Typical Capacitor Equipment Connected Grd Wye with

Two Series Sections/Phase in a Single Stack
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• Cost—The cost to implement each control strategy varies depending on sophistication and

whether potential, current, or both inputs are required and the required control and auxiliary

equipment (operating transformer, control secondary, current transformer, etc.).

The optimum choice of control will always be the least expensive type that will switch the capacitor bank

on the required schedule. To facilitate comparison, the operating characteristics and relative cost of

common controls used are summarized in Table 5-37:

Table 5-37: Comparison of Operating Characteristics of Capacitor Controls

Type of

Control Advantages Disadvantages

Manual No control device necessary since the

bank’s switching device is operated by

substation personnel.

Requires attendants at the substation.

Time Non-electrical control input allows

application at any point on the circuit.

Can only be applied on feeders where

power factor and demand have a regular

daily variation that is repeated weekly. Use

limited to locations where established

switching schedule will not cause high

voltage on holidays or during other

abnormally light load periods. Insensitive to

abnormal voltage conditions.

Temperature Non-electrical input allows application

at any point on the circuit. Connects

capacitors when the outside ambient

temperature exceeds a temperature

set point.

Can only be applied where direct correlation

with load increases and temperature can be

established such as air conditioning loads.

Voltage Applies and removes shunt capacitors

when system voltages operate outside

of allowable voltage tolerances.

Can only be applied where voltage drops

appreciably under load. More difficult to

coordinate with voltage regulators and other

switched capacitor banks. Requires

separate potential transformer.

Current Can be applied at any point on the

circuit where the load current can be

monitored. Nondirectional. Responds

to current changes. Current and

voltage source available for general

testing on feeder.

Requires current transformer. Adjustment

slightly more complex than other controls.

Kilovar Most effective in minimizing losses

because it senses fundamental

quantity being corrected (kVAR).

Current and voltage sources available

for general testing on feeder.

Most expensive control method. Directional

(reversing direction of feed will reverse

signal). Insensitive to abnormal voltage

conditions. Requires current transformer

and potential transformer.

5.6.6.2.1 Manual: The simplest means to accomplish capacitor bank switching is the manual control.

Substation personnel, observing the need for capacitor banks to be switched, either go out to the yard and

physically operate capacitor bank switching devices or operate them remotely from a panel.

5.6.6.2.2 Time Controls: Cooperatives wishing to relieve their personnel of the responsibility for

manual capacitor bank control can substitute automatic controls. One of the most economical automatic

controls is the time device. Time control switches the capacitor bank on or off at a fixed time each day.

It usually takes the form of a clock that operates on station service ac. An electrical or mechanical carryover device is required for each time clock to keep it running during temporary power outages. It may
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include provisions for omitting control on weekends. Time control is most useful when the reactive load

is periodic and predictable. This should be determined by examining the daily load curves. The time

control does not require the monitoring of any electrical quantities.

Modern time clock controllers are microprocessor based, which provides 24-hour, 7-day programmable

control. These devices typically use lithium batteries for backup during power outages.

5.6.6.2.3 Temperature Controls: In certain areas of the country, the reactive load is more closely

aligned with temperature variation than with anything else. Such loads do not exhibit the periodicity that

would suggest the use of time clocks. They are often associated with the operation of air conditioners. A

temperature control can be used to apply shunt capacitors with increases or decreases in ambient

temperature. The temperature controller’s thermostat responds to changes in ambient temperature to

provide input to the switching device. A determination of the relationship between kVAR load and air

temperature is required to be able to set the temperature controller. As with time controls, these devices

are relatively economical and do not require the monitoring of electrical quantities.

5.6.6.2.4 Voltage Controls: The most straightforward and simplest of the controls that respond to

changes in electrical conditions is the voltage control.

The voltage found at a point on an electrical system is the summation of all conditions on the system.

Capacitors increase the voltage at the point where they are applied. Thus, a low voltage would suggest

the need for capacitors, and a high voltage would call for their removal. This would not be true at a

location close to the output of a compensated regulator where high voltage is developed with peak loads.

A simple capacitor control based only on voltage would not give the desired results if applied in a

segment of the system where compensation in regulators cancelled the significance of high and low

voltage as an indicator of loads. The bandwidth of the control should be larger than the voltage change

caused by switching of the capacitor bank to prevent “hunting.” Hunting refers to unintentional cycling

of capacitor banks “on” and “off” due to incorrect settings on capacitor controllers.

Voltage controls usually respond to signals from a nominal 120-volt source ranging between 108 and

132 volts. If the switching device is a vacuum switch, the primary of the VT monitoring voltage should

be protected by means of a distribution class surge arrester. This protects against high voltages produced

by the chopping effect of the switches.

5.6.6.2.5 Current Controls: A simple answer to many of the desired objectives of capacitor control is

the measurement and subsequent switching of the capacitors according to the flow of current. This type

of controller is suitable where voltage is well regulated and the power factor of the load remains constant

with variation in kilowatt loading, or if the power factor of the circuit varies predictably with variation in

kilowatt loading.

This solution is particularly attractive on circuits consisting primarily of a known group of electric

motors. Typical examples would be a circuit for pumps on a major water supply or for irrigation, driven

by electric motors and located a considerable distance from the source, or on any application where there

is a dependent relationship of reactive (kVAR) load with current.

Heavy loads on circuits of this type could occur at any time of day or night and any day of the week.

Capacitors used on this application would be dedicated to serving these motor loads. Switching of the

capacitors is, therefore, logically a function of these loads.
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Current controls are sensitive to signals between 0.5 and 5 amperes from a 5-ampere CT secondary. As a

safety feature to protect against high secondary open-circuit voltages, the control should be arranged to

short circuit the CT secondary leads automatically when the control circuit is opened.

In some instances several banks of capacitors are placed in the same substation to facilitate incremental

application of kVAR to the bus. There might be, for example, a fixed capacitor bank and two switched

banks controlled by a two-step voltage controller. In addition to setting multi-step controls to avoid

“hunting,” the capacitor switches should be selected with the aim of protecting them from the

consequences of back-to-back capacitor switching.

5.6.6.2.6 VAR Controls: The most sophisticated control method, the VAR control, responds directly

to VAR demand. This type of controller is suitable where voltage is regulated and power factor varies

unpredictably with variation in kilowatt loading.

Care has to be taken to set the control so that the response of the system to the presence or absence of the

capacitor bank is less than the bandwidth represented by the maximums and minimums of the settings on

the control. For example, if a 2100 kVAR bank of capacitors is applied, the “turn off” setting of the

control should be greater than the “turn on” setting +2100 kVAR. This is necessary to prevent “hunting.”

VAR controls are usually arranged to respond to signals from a VT with a secondary rating of 120 volts

connected across two phases and a CT with a secondary rating of 5 amperes in the third phase. This

arrangement provides a 90-degree phase angle between the voltage and the current signals at unity power

factor.

Some VAR controls have capacitors in either the voltage or current inputs to retard the phase angle and

thus make it possible to read VAR signals by monitoring fewer than three phases.

In addition to the above controls, there are a number of combination types, of which the most common are

time and temperature, and voltage with current bias.

Modern capacitor controllers allow implementation of one or more of the above control functions to meet

each project’s unique requirements. The following functions are commonly used:

• Time and temperature

• Voltage with current bias

• Voltage with time bias

5.6.6.2.7 Protective Controls: Capacitor switching devices are also arranged to operate in response to

signals from protective controls. These are described further under Section 5.6.7, “Protection.”

5.6.6.3 Control Power

5.6.6.3.1 Wiring: Instruct the capacitor bank’s manufacturer to provide a common junction box to

facilitate field connections for all secondary circuits.

5.6.6.3.2 Source: Most controls with lockout relays require nominal 120 volts ac for operation, but

they can be arranged for other voltages. The switches that are controlled, however, may be ac or dc at

any number of voltages. Tell the capacitor bank’s manufacturer the control voltages available at the

installation.
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5.6.6.3.3 Transfer and Control Switches: Many controls have selector switches for “automatic or

manual” operation and for “local or remote” location. When the “local–remote” switch is set for “local”

and the “automatic–manual” switch is set for “manual,” the capacitor switching device may be controlled

from the local control cabinet. If the “automatic–manual” switch is set for “automatic,” the capacitor

switching device will respond to automatic control signals from the bank’s controller unless a protective

override opens the device and locks it out.

5.6.7 Protection

Additional information on capacitor bank protection can be found in RUS Bulletin 1724D-112.

5.6.7.1 Fuses: Electric devices (or circuits) are generally fused for one or both of two basic reasons:

1. To protect the device from overloads

2. To protect the system from failure within the device

In some cases, such as group fusing with cutouts, the fuse may be used as a manual disconnect or

switching means. This is not, however, a basic function of a capacitor fuse. Because capacitors, for

economic reasons, are designed for operation at high dielectric stress, a certain calculated failure rate is to

be expected. Thus, capacitor unit fuses are used primarily to protect the electrical system from dielectric

failures that are expected to occur.

Conventional capacitor units are typically protected by an external fuse connected in series with each

capacitor unit. Internally fused units are available that eliminate the need for external fuses. Internally

fused capacitor units utilize fuse links connected in series with each of the unit’s capacitor elements. An

internally fused capacitor unit comprises a large number of capacitor elements connected in parallel with

only a few groups of parallel elements connected in series.

Figure 5-19 illustrates capacitor units utilizing external and internally fused capacitor elements.

In general, capacitor banks utilizing internally fused capacitor units are configured with fewer capacitor

units in parallel and more series groups compared to banks configured with external fuses.

Recent advances in capacitor bank design include the application of fuseless capacitor banks. This design

utilizes capacitor units manufactured from polypropylene film. This technology provides a highly reliable

design, virtually eliminating the need for fuses in many applications. These capacitor banks are simpler

and more economical to build and operate compared to fused banks. The fuseless design has been mainly

applied at voltages ranging from 69 kV to 230 kV.

5.6.7.1.1 Functional Requirements of Capacitor Fuses: Capacitor fuses have to accomplish the

following principal functional requirements:

1. Isolate a faulted capacitor unit, bank, or portion of a bank from the circuit to which it is

connected with negligible disturbance to the remainder of the bank or system.

2. Prevent case rupture by clearing the faulted capacitor from the circuit before the gas generated

by the internal fault bursts the capacitor case, possibly damaging adjacent units or equipment,

injuring personnel, or discharging dielectric liquid into the ecosystem.

3. Indicate the location of the failed capacitor (externally fused units only).
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Figure 5-19: Typical Internally and Externally Fused Capacitor Units

4. Carry normal capacitor overloads, transient inrush currents, discharge currents. and rated

current without spurious operation and without affecting the ability of the fuse to perform the

first three functions.

5.6.7.1.2 Types of Applications for Capacitor Fuses: There are two general schemes used for external

fusing of capacitor banks: group fusing and individual fusing.

5.6.7.1.2.1 Group Fusing: Within the limits of the four required fuse functions, fuses may be applied

to individual groups of paralleled capacitor units. Group fuses have to also be capable of interrupting the

expected 60 Hz fault current. This type of fusing is not often used on substation capacitor banks.
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Group fusing of capacitor banks may be advantageous for relatively small ungrounded-wye capacitor

banks where operation of a group fuse isolates an entire phase without detrimental effect on the system.

Elimination of the unit fuses permits more compact rack designs and simpler buswork.

However, care should be taken in the application of group fuses to be sure that fault current through the

fuse will cause it to operate and clear before the combined system fault current and current discharge

from adjacent capacitors into the faulted unit can cause case rupture. By providing adequate coordination

between the fuses’ “maximum total clearing” curve and the capacitor’s case rupture curve, case rupture

can be avoided.

5.6.7.1.2.2 Individual Fusing: In a capacitor bank or equipment having a number of units connected

in parallel, each capacitor unit will usually have its own fuse. The series combination of each capacitor

unit and fuse will be in parallel with other capacitors. Often, for multiphase arrangements and various

series parallel groupings, backup bus fault protection is also provided by either circuit breakers or large

power fuses.

With individual fusing, the loss of any individual capacitor does not necessarily result in the loss of the

bank, the phase, or even the series section. Adjacent units discharge into the faulted unit and its fuse,

allowing the fuse to quickly clear the fault.

Finally, if for any reason a reduction needs to be made in the kVAR of the bank, this can be accomplished

easily by simply removing the appropriate fuses or links. The spare rack spaces then serve as a storage

shelf for the extra capacitors.

5.6.7.1.3 Effect of Connections on Capacitor Fuses: The requirements for individual capacitor fuses

are affected by the capacitor bank connections as well as the system to which the bank is connected.

Non-current-limiting fuses, which are cheaper than the current-limiting type, can be used wherever bank

connections can be arranged to limit the available fault current. Possible capacitor bank connections are

the following:

5.6.7.1.3.1 Three-Phase Grounded Wye and Delta: Where only one series section of paralleled units

per phase is used, and the equipment is connected three-phase grounded wye or delta, the unit fuse is

subjected to the full available system short circuit whenever a capacitor unit fails. High-interruptingcapacity, current-limiting fuses are required in these situations when the fault current is on the order of

4000 amperes or higher.

5.6.7.1.3.2 Ungrounded Wye: When a three-phase wye connection is used with only one series

section of paralleled units per phase and the neutral is left floating, the unfaulted phases will limit the

current supplied to the faulted phase from the system. The fuse on the faulted unit will see a maximum of

only three times normal bank phase current, and generally a less expensive low-interrupting-capacity fuse

can be used. The small risk of simultaneous failure occurring in units of different phases that would

result in a phase-to-phase fault is usually accepted.

The above applies to capacitor banks where single-bushing capacitor units have been mounted on

insulated racks. However, capacitor units should be capable of interrupting system phase-to-ground fault

current where two-bushing capacitor units are mounted on grounded racks. If lower rated fuses are used,

fault clearing might not be accomplished by the fuse, which will require the bank’s overcurrent relaying

to operate a switching device capable of interrupting the fault current.
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5.6.7.1.3.3 Series – Parallel: Series-connected groups of paralleled capacitor units can provide an

effective means of limiting fault current to a level where less expensive non-current-limiting fuses can be

used. This applies to installations where the parallel kVAR of individual groups does not exceed

4,650 kVAR.

The bank voltage rating is the principal factor that determines what series-parallel arrangement to use,

along with the type of equipment. Multiple series section arrangements are not practical in equipment

below 15 kV and in housed equipment. Consult the capacitor manufacturer regarding fusing for a given

bank arrangement and specified maximum fault current.

5.6.7.2 Protective Controls: The purpose of a capacitor bank’s protective control is to remove the

bank from the bus before any units are exposed to more than 110 percent of their voltage rating. When

capacitor units in a capacitor bank fail, the amount of increase in voltage across the remaining units

depends on the connection of the bank, the number of series groups of capacitors per phase, the number of

units in each series group, and the number of units removed from one series group. Protective controls

are available for grounded neutral capacitor banks, ungrounded neutral capacitor banks, and capacitor

banks connected wye-wye.

Where the capacitor bank is switched by a circuit breaker, the protective control does not need a lockout

relay since breakers are usually equipped internally with lockout functions. However, where other

switching means are provided, the protective control should have a lockout with a manual reset function.

5.6.7.2.1 Grounded Neutral: The most straightforward protective control for grounded neutral

capacitor banks is the neutral relaying control. This scheme operates on the neutral current generated

because of the unbalance caused by capacitor failures in any phase.

The major advantage of the neutral protection scheme is that it is relatively inexpensive. If there aren’t

too many series sections, this control can be set to alarm and trip at two different levels of neutral current

to provide early detection that a problem exists in the bank and adequate protection should additional

capacitor units fail. It is important to be aware of this protective control’s disadvantages. Third-order

harmonics have to be blocked out of the control, since they will flow in the neutral regardless of whether

or not the bank is unbalanced. This blocking is often accomplished by means of a small capacitor in the

control that tunes the sensitive element to 60 Hz.

It is noted that this control is not sensitive to overvoltages caused by the loss of equal number of capacitor

units in one or more groups in each phase. However, this is usually not a significant limitation. It may be

too sensitive and turn off the bank on unit failures occurring in different series sections of the same phase,

even though no series group experiences greater than 110 percent overvoltage. Finally, since the

associated CT has to be large enough to handle continuously the third-order harmonics (usually assumed

to be 10 percent per phase of fundamental phase current, if no better information is available), the signal

at the CT secondary may be too small for relays of ordinary sensitivity. This can be overcome by using

three CTs, one in each phase, and connecting the secondaries in parallel and relaying for the zero

sequence current.

This protective scheme responds only to capacitor overvoltages caused by unbalance and does not protect

against capacitor overvoltage due to changes in three-phase supply voltage.

5.6.7.2.2 Ungrounded Neutral: The floating-neutral protective control is similar to that for the

grounded neutral bank, except that a VT is used in the neutral (usually rated 15 kV) to indicate neutral
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voltage shift on loss of units. The control is voltage sensitive and subject to the same limitations and

advantages as the protective control for grounded neutral capacitor banks.

5.6.7.2.3 Wye-Wye: The wye-wye capacitor bank may be protected by means of a CT between the

two ungrounded neutrals. Care should be taken to avoid exceeding individual capacitor unit fuses’

interrupting ratings when applying wye-wye banks having one series group per phase. Dependent on the

number of capacitors in each phase, there may be sufficient discharge current from parallel capacitor units

into the faulted unit to exceed its fuses’ interrupting rating. The impedance of the neutral CT is

negligible; however, it cannot limit discharge currents into the faulted unit. This scheme tends to be fairly

sensitive, and the CT does not require gap protection, even if a vacuum switch is used. The buswork,

however, can be difficult to design.

5.6.7.3 Protection of Current and Voltage Transformers Installed in Capacitor Banks

5.6.7.3.1 Current Transformers: Switching of capacitors produces transient currents that can produce

overvoltages on secondary circuits. Overvoltage protection is required to prevent damage to the current

transformer winding and connected burdens. Secondary protection generally involves the correct

application of a high-current-rated varistor or spark gap connected directly across the current transformer

terminals. Varistors applied to secondary windings should be selected with sufficient energy-absorbing

capability to withstand secondary oscillations. Additionally, current transformers that have wound

primary windings require overvoltage protection by adding an arc gap or arrester across the primary.

5.6.7.3.2 Voltage Transformers, Capacitor-Coupled Voltage Transformers, and Resistance Potential

Devices: AC voltage sources of various types are used in capacitor bank applications for control and

protection schemes. Overvoltage protection of these devices is normally required since transients or

surges produced during switching can overstress primary-to-secondary insulation and secondary-toground insulation. Surge arresters are typically used for primary protection. Varistors or spark gaps are

typically used for secondary protection.

AC voltage sources should be specified for full line voltage with primary overvoltage protection added to

provide additional protection.

5.6.7.4 Bus Insulation Systems: Unlike enclosed capacitor banks, open-rack capacitor banks have

exposed live parts. In some cases, this exposure has resulted in bank outages due to isolation of faults

originated by birds or animals bridging live parts or live parts to ground. One straightforward prevention

of this is to use edge-mounted equipment, since the electrical clearances in the racks used in this

equipment are sufficiently liberal and make it highly unlikely that any bird or animal will be large enough

to bridge any of the live parts.

However, if upright racks are used and birdproofing is deemed necessary, bus bar insulation systems are

commercially available that can be used to protect against accidental bridging of conductors commonly

caused by birds and animals. Heat shrinkable tubes, tapes, and sheets and molded fittings allow for

simple installation and flexibility to cover most conductor shapes and sizes. Although enclosed capacitor

banks have very little exposure to faults by rodents, bus bar insulation systems are sometimes applied in

areas where animals such as snakes and lizards are prevalent. For a description of these protective

devices, see CRN’s Animal-Caused Outages (Project 94-5).

Capacitor bank manufacturers can apply bus insulation at the factory, or it can be applied in the field.
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5.6.7.5 Lightning: Lightning surges and the switching of capacitors can result in significant

overvoltages. Generally, capacitor banks installed in a substation will be protected from lightning and

switching surges by the same devices that protect the substation. However, in regions where lightning

activity is high, or in applications involving frequent switching of a capacitor bank, it may be appropriate

to install surge arresters at the capacitor bank to limit transient overvoltages.

Coordinate insulation levels of installed equipment—substation and shunt capacitor bank—for effective

lightning and switching surge protection.

5.6.7.6 Corona: For systems with voltages above 100 kV, consult the capacitor manufacturer about the

advisability of providing corona shields.

5.6.8 Grounding and Short-Circuiting of Capacitor Banks

In accordance with NEMA Std. CP-1, substation capacitor units are built with internal discharge resistors

so that the residual voltage is reduced to 50 volts or less within 5 minutes after the capacitor unit has been

disconnected from its source of supply.

Manually operated switches should be provided to short-circuit and ground each series section of the

capacitor bank after it has been disconnected from the circuit but before it is handled by personnel to

avoid potentially exposing personnel to hazardous voltages at capacitor terminals.

The duty on these switches is not severe, and most bank manufacturers can supply single hook-stickoperated switches for open-rack bank designs and gang-operated switches for enclosed capacitor bank

designs to perform both the shorting and grounding functions. While not always required, it may be

desirable to specify interlock schemes to prevent the operation of shorting and grounding switches on live

circuits and to keep personnel from access to capacitor bank live components when the banks have not

been shorted and grounded.

5.6.9 Mounting

There are two common positions for mounting capacitor units in outdoor substation racks: upright and

edge mount. These mounting configurations are illustrated in Figures 5-20 and 5-21.

5.6.9.1 Open Rack Design: The upright mounting position is generally preferred for capacitor units up

to 10 kV and edge mount for units above 10 kV. Upright racks are relatively compact and provide a

metal framework on the outside, which tends to protect the capacitor units. Edge-mount units provide

ample clearances and protection from bus and bushing flashovers caused by birds, rodents, and other

causes. They do, however, require more physical ground space.

In the United States, power capacitors are mounted by means of two flanges spaced 39.7 cm (15-5/8 in.)

apart.

Where units are protected by means of expulsion fuses, it is necessary to provide a minimum of 3 feet of

air clearance plus strike distance between the ends of the fuses and any grounded metal objects to prevent

inadvertent flashovers on fuse operation caused by ionized gases contacting the metal objects. For nonexpulsion fuses, the additional 3 feet of clearance is unnecessary.

Normally, capacitor equipment and its substructures are designed to withstand minor earthquake
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Figure 5-20: Capacitors Vertically Mounted. Ref. NEMA Std. CP-1, FIG. 4-1. Reproduced with

permission of the National Electrical Manufacturers Association.

conditions, 129 km/h (80 mph) wind, and 1.27 cm (0.5 in.) of ice (non-simultaneously). Where

conditions are more severe than this, the capacitor manufacturer should be told.

Capacitor racks and housings have provisions for mounting of up to three tiers, with no more than two

rows of units per tier. There should be unrestricted air circulation around the units. If ambient conditions

are extremely dusty, smoky, or salty, consult the capacitor manufacturer as to the advisability of extra

creep bushings and insulators and more generous strike clearances between live parts.
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Figure 5-21: Capacitors Horizontally Mounted. Ref. NEMA Std. CP-1, FIG. 4-2. Reproduced with

permission of the National Electrical Manufacturers Association.

Capacitor equipment is often mounted on 2.44-meter (8-foot) substructures to provide adequate ground

clearance, personnel safety, ventilation, and a place to mount accessories. This clearance should be

carefully checked and increased if necessary to meet applicable safety codes.

5.6.9.2 Enclosed Bank Design: Manufacturers of enclosed capacitor banks custom design each bank

for its unique application. Efforts are made by the manufacturer to provide a compact design. The

overall size of the enclosure depends on the number of installed components and orientation and

mounting of these components. The designer may mount individual capacitor units horizontally or

vertically to reduce the overall size of the bank.

Non-expulsion, capacitor-rated, current-limiting fuses are used rather than expulsion type to fuse

externally fused capacitor units. Expulsion fuses are not to be used since they do not support a compact

bank design. These fuses require clearances for fuse expulsion in addition to electrical clearances.

Internally fused capacitor units are often used since no external fuses are required and they allow for a

more compact design.
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5.6.10 Factory Tests

In the United States, shunt power capacitors are usually tested in accordance with NEMA Std. CP1,

which includes production and design tests.

5.6.11 Inspection and Maintenance

IEEE Std. 1036 provides guidelines for inspection, maintenance, and field testing of shunt capacitor

banks.

5.6.12 Typical Technical Specification

5.6.12.1 General

5.6.12.1.1 Scope: This specification covers the manufacture of (1) _________ kVAR, ________ kV,

60 Hz, 3-phase (indoor) (outdoor) (open-rack) (metal-enclosed) shunt capacitor bank assembly, connected

(ungrounded wye) (delta) (grounded wye) (double wye). Each capacitor bank shall comprise _________

individual kVAR, single-phase, kV, (single) (double) bushing, kV BIL capacitors.

There shall be capacitors individually connected in parallel per phase and series groups.

The manufacturer shall guarantee in writing that each capacitor bank meets the requirements of

_____________________ and other applicable American standards in all respects. These include the

most recent version of all applicable codes and standards, including, but not limited to, those of the

following: American National Standards Institute, National Electrical Code, National Electrical Safety

Code, American Society for Testing and Materials, and American Society of Civil Engineers.

The capacitor units shall be mounted in (upright) (edge-mount) racks that shall be (fully equipped) (partly

equipped) and arranged for a maximum of ________ units each.

_________ banks of capacitors, each rated ________ kVAR, will ultimately operate in parallel on the

same bus (and will be separately switched). The banks will be separated by approximately ________ feet

of bus, anticipated to have a maximum inductance of ________ microhenries. The manufacturer shall

make suitable provision to limit the inrush currents due to back-to-back capacitor switching to the

capabilities of the switches and fuses. A bus reactor would be the user’s responsibility.

5.6.12.2 Controls: Each capacitor bank assembly shall (not) be equipped with (neutral unbalance

detection – grounded and ungrounded wye systems) (unbalance detection – delta systems).

Each capacitor bank shall be equipped with a (voltage) (current) (VAR) (current-compensated voltage)

(time) (temperature) (other ) control. (Cross out if not applicable.)

The secondary control voltage available at the substation will be volts, (VAC) (VDC).

Enclosure (Metal-Enclosed Only)

The manufacturer shall furnish an enclosure rated for (indoor) (outdoor) installation of (dead front) (live

front) construction to house capacitor bank components. The enclosure shall be constructed in

accordance with the latest applicable industry standards and governing local and National Electrical Code

requirements. The enclosure shall be constructed of not less than U.S. gauge A-60 “galvaneel”

steel.
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The manufacturer shall clearly identify bus phase sequence in the cable entrance section in conformance

with IEEE Std. C37.20.2. Tying bars for support of cables shall be provided. Cable terminals, NEMA

Type , shall be provided in sufficient quantity to terminate cables per phase.

The enclosure shall be provided complete with access doors, lifting provisions, ventilation, heaters,

signage, and nameplate.

Elevating Substructure(s) (Open Rack Only)

The manufacturer shall (not) furnish substructures that will elevate the capacitor racks a minimum of

(2.44) (_____) meters (8) (_____) feet above the ground.

Surge Arresters

The manufacturer shall provide (distribution) (intermediate) (station) class surge arresters with a

maximum continuous operating voltage of kV.

Switching Devices

The capacitor bank shall be furnished with the following switching devices:

 Capacitor Switch(es) – (single-pole, vacuum switches) (three-pole, vacuum switches) (single-pole,

oil switches) (vacuum circuit breaker) (circuit switcher), kV, kV BIL, amp, kA –

Asymmetrical Momentary, kA – Symmetrical Interrupting

 Main Disconnect Switch(es) – three-pole, group-operated, non-load-break disconnect switch,

 _____kV, kV BIL, amp, kA – Asymmetrical Momentary

 Shorting Switches – (single-) (three-) pole, (group-operated), non-load-break disconnect switch,

 ______kV, kV BIL, amp, kA – Asymmetrical Momentary

 Grounding Switch(es) – Ground switch with fully insulated, manually operated handle to ensure

that all stored energy has been discharged from capacitors while providing safety and visual

ground indication. Rated kV, kV BIL, amp, kA – Asymmetrical Momentary

In-Rush Current Limiting Reactors

If required, the manufacturer shall provide single-phase inrush current-limiting reactors to limit inrush

current due to bank energization or back-to-back capacitor switching to the capabilities of switches and

fuses.

Key Interlocking Scheme

The manufacturer shall provide all key interlocking hardware to implement a key interlocking scheme

designed by the manufacturer to prevent entry by personnel into any live portions of the shunt capacitor

bank until the bank has been de-energized for at least 5 minutes and grounding and shorting switches

have been closed.

Main Fusing

The manufacturer shall (not) provide (current-limiting) power fuses to isolate fault conditions within the

shunt capacitor bank.

Capacitor Unit Fusing

The manufacturer shall provide (internally) (externally) fused capacitors. (For externally fused

capacitors, each capacitor shall be individually fused to protect against case rupture with a current-
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limiting fuse. Each fuse shall be non-expulsion, capacitor-rated, current limiting, with blown fuse

indication. Fuse size shall be determined by the manufacturer to ensure protection against case rupture.)

5.6.12.3 Accessories: Base and stack insulators shall be high strength (cap and pin) (station post) and

shall be colored (ANSI #70 gray) (brown).

The manufacturer shall furnish all necessary racks, shelves, superstructures, buswork, insulators,

connections, terminals, and hardware. If aluminum connections are involved, a container of oxide

inhibitor shall be furnished. A can of touch-up paint of the same color as the capacitors shall be

furnished.

Any necessary instrument transformers for proper operation of the controls shall be furnished. They shall

be suitably protected by means of arresters, protector tubes, or gaps, as required.

5.6.12.4 Submittals: The manufacturer shall supply suitable drawings (for approval) (for installation)

(for record) as follows:

a. Outline drawings complete with elevations, section views, and base details

b. Auxiliary equipment outlines

c. Three-line diagram

d. Control schematics and wiring diagrams

e. Interconnection diagram

f. Bill of material

g. Hardware schedule

h. Base plan

The manufacturer shall also furnish ________ copies of pertinent

a. Instruction books

b. Spare parts lists

c. Maintenance manuals

d. Fuse curves (minimum melt and maximum total clearing)

e. Capacitor case bursting curves

f. Test reports

g. Manufacturer’s catalog data sheets

5.6.12.5 Information To Be Furnished with Proposal: Each proposal submitted to furnish the

capacitor banks covered by this specification shall include, in addition to the quoted price and promised

delivery, the following information in the form and sequence indicated:

5.6.12.5.1 Drawings and Descriptive Data:

A. Outline and arrangement drawings for each bank section including overall dimensions,

weights, and breakdowns and weights for shipment

B. Required locations for owner’s mounting bolts and channel

C. Catalog cut sheets and other data describing the equipment proposed

5.6.12.5.2 Ratings and Performance: Shunt capacitor bank components are capable of meeting the

following ratings and performance under the altitude and conditions specified:
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A. Cable Entrance (Describe):

_______________________________________________________________________

_______________________________________________________________________

_______________________________________________________________________

B. Main Bus:

1. Continuous Current Rating ____________A

2. Withstand Capability ____________kA-rms-Sym

3. Bus Support Type and Cantilever ____________

4. Bus Material and Insulation ____________

C. Ground Bus:

1. Description

____________________________________________________________________

____________________________________________________________________

2. Continuous Current Rating ____________A

D. Surge Arresters:

1. Manufacturer ____________

2. Style No. ____________

3. Type ____________

4. Class ____________

5. MCOV ____________kV

E. Disconnect Switches:

1. Manufacturer ____________

2. Style No. ____________

3. Rated Maximum System Voltage ____________kV

4. Basic Impulse Level ____________kV

5. Low-Frequency Withstand Voltage ____________kV

6. Rated Continuous Current ____________A
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7. Momentary Rating ____________kA-rms-Asym.

8. No. of Auxiliary Contacts ____________

F. Main Fusing:

1. Manufacturer ____________

2. Style No. ____________

3. Rated Maximum Voltage ____________kV

4. Basic Impulse Level ____________kV

5. Rated Continuous Current ____________A

6. Interrupting Rating ____________kA-rms-Sym.

7. Current Peak Let-Thru

@ Interrupting Rating ____________A-Peak

G. Current-Limiting Reactors:

1. Manufacturer ____________

2. Type ____________

3. Rated Maximum System Voltage ____________kV

4. Basic Impulse Level ____________kV

5. Continuous Current ____________A

6. Rated kVA ____________kVA

7. System Frequency ____________Hz

8. Inductance ____________μH

9. Q-Factor ____________

10. Tolerance ____________

11. Cooling Method ____________

H. Capacitive Switching Device:

1. Manufacturer ____________
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2. Type ____________

3. Rated Maximum System Voltage ____________kV

4. Basic Impulse Level ____________kV

5. Rated Continuous Current ____________A

6. Close and Latch Capability ____________kA-rms-Asym.

7. Interrupting Capability ____________kA-rms-Sym.

8. Control Option ____________

9. Operating Mechanism

a. Control Voltage ____________

b. Mechanism Type ____________

c. Close Time ____________

d. Trip Time ____________

e. No. of Auxiliary Contacts ____________

f. Accessories ____________

I. Capacitor Units:

1. Manufacturer ____________

2. No. of Installed Units per Bank ____________

3. No. of Spare Units per Bank ____________

4. Case Material ____________

5. Fusing Type (Internal) (External) ____________

6. Bushing Configuration ____________

7. Rated Maximum System Voltage ____________kV

8. Basic Impulse Level ____________kV

J. Ground Switch:

1. Manufacturer ____________
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2. Rated Continuous Current ____________A

3. Momentary Rating ____________kA-rms-Sym.

K. Key Interlock System:

1. Manufacturer ____________

2. Description

____________________________________________________________________

____________________________________________________________________

____________________________________________________________________

L. Auxiliary Power Transformer:

1. Manufacturer ____________

2. Style No. ____________

3. Rated kVA ____________ kVA

4. Connection ____________

5. Rated Maximum System Voltage ____________ kV

6. Basic Impulse Level:

a. Primary ____________kV

b. Secondary ____________kV

7. Fusing - Primary:

a. Manufacturer ____________

b. Style No. ____________

c. Rated Maximum System Voltage ____________kV

d. Maximum Sym. Interrupting Capability ____________kA-rms-Sym.

8. Fusing - Secondary:

a. Manufacturer ____________

b. Style No. ____________

c. Rated Maximum System Voltage ____________V

d. Maximum Sym. Interrupting Capability ____________kA-rms-Sym.
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9. Surge Protection:

a. Manufacturer ____________

b. Style No. ____________

c. Energy Discharge Capability ____________Joules

M. Instrument Transformer - Current:

1. Phase Unbalance Relay Current Transformer:

a. Manufacturer ____________

b. Style No. ____________

c. Accuracy Class ____________

d. Ratio ____________

2. Line Metering Current Transformer:

a. Manufacturer ____________

b. Style No. ____________

c. Accuracy Class ____________

d. Ratio ____________

3. Surge Protection – Line Metering Current Transformer:

a. Manufacturer ____________

b. Style No. ____________

c. Energy Discharge Capability ____________Joules

N. Controller - Combined Control and Relaying Packages:

1. Manufacturer ____________

2. Style No. ____________

3. Control Description

____________________________________________________________________

____________________________________________________________________

____________________________________________________________________
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4. Protective Functions

____________________________________________________________________

____________________________________________________________________

____________________________________________________________________

5. Accessories

____________________________________________________________________

____________________________________________________________________

____________________________________________________________________

O. Test Switches:

1. Manufacturer ____________

2. Style No. ____________

P. Terminal Blocks:

1. Manufacturer ____________

2. Style Nos. ____________

Q. Auxiliary Heating, Ventilation, Power, and Lighting (Metal-Enclosed Only):

1. Heating - Description

____________________________________________________________________

____________________________________________________________________

____________________________________________________________________

2. Ventilation - Description

____________________________________________________________________

____________________________________________________________________

____________________________________________________________________

3. Auxiliary - Power and Lighting - Description

____________________________________________________________________

____________________________________________________________________

____________________________________________________________________

R. Equipment Testing Included:

______________________________________________________________________

______________________________________________________________________

______________________________________________________________________

5.6.12.5.3 List of Recommended Spare Parts: Seller shall provide list of recommended spare parts,

quantity, and unit price.
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5.6.13 References

Anderson Electric Corporation, Technical Data – A Reference for the Electrical Power Industry, Leeds,

Alabama, p.164.

ANSI Publication C107.1, “Guidelines for Handling and Disposal of Capacitor and Transformer Grade

Askerels Containing Polychlorinated Biphenyls.”

ANSI Std. C37.06, “Preferred Ratings and Related Required Capabilities for AC High-Voltage Circuit

Breakers Rated on a Symmetrical Current Basis.”

ANSI/IEEE Std. C37.04, “IEEE Standard Rating Structure for AC High-Voltage Circuit Breakers Rated

on Symmetrical Current Basis.”

ANSI/IEEE Std. C37.012, “IEEE Application Guide for Capacitance Current Switching for AC HighVoltage Generator Circuit Breakers Rated on a Symmetrical Current Basis.”

ANSI/IEEE Std. C37.99, “Guide for the Protection of Shunt Capacitor Banks.”

Dow Chemical Company, “Dow XFS-4769L Capacitor Fluid,” December 2, 1975.

Dow Chemical Company, “Environmental Impact Statement, Dow XFS-41G9L Capacitor Fluid,”

Midland, Michigan.

Dow Corning Corporation, “Dielectric Properties of Dow Corning Silicone Fluids,” 1975.

Dow Corning Corporation, “Dow Corning Dielectric Liquids for Power Transformers,” 1975.

Duckett, D.A. (Chief Product Engineer, RTE Corporation), “Environmentally Acceptable Insulating

Fluids May Replace Askerel,” Presentation to General Meeting of Edison Electric Institute,

Transmission and Distribution Committee, Minneapolis, Minnesota, May 8, 1975.

IEEE Std. 76, “IEEE Guide for Acceptance and Maintenance of Transformer Askerel in Equipment.”

IEEE Std. 519, “Recommended Practices and Requirements for Harmonic Control in Electrical Systems.”

IEEE Std. 1036, “Guide for Application of Shunt Power Capacitors.”

IEEE Std. C37.20.2, “Standard for Metal-Clad and Station Type Cubicle Switchgear.”

IEEE Std. C57.16, “IEEE Standard Requirements, Terminology, and Test Code for Dry-Type Air-Core

Series-Connected Reactors.”

Jordan, William III, “Electrical/Insulating Materials,” Engineering Materials Handbook. New York:

McGraw Hill Book Company, 1958.

Lindstrom, C.O., “Series and Shunt Capacitor Banks; Provision for Collection of PCB Leakage,” Memo

EKT1-COL/BJ, Swedish State Power Board, August 15, 1974.
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McGraw-Edison Company, “An Environmentally Acceptable Liquid Dielectric for Power Capacitors,”

Bulletin 76015, March 1976.

Murch, R.H. “New Capacitor Impregnants,” St. Louis, Mo.: Monsanto Industrial Chemicals Company.

National Rural Electric Cooperative Association, Cooperative Research Network, Animal-Caused

Outages. Project 94-5. Arlington, Va.: NRECA, 1996.

NEMA Std. CP-1, “Shunt Capacitors.”

Pratt, R.A., W.W. Olive Jr., B.D. Whitman, and R.W. Brown, “Capacitor Case Rupture Withstand

Capability and Fuse Protection Considerations,” Presentation to Edison Electric Institute,

Transmission and Distribution Subcommittee, May 5-6, 1977.

RUS Bulletin 1724D-112, “The Application of Shunt Capacitors to the Rural Electric System.”

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”

Sangamo Electric Company, Power Capacitor Application, Measurement and Control (papers), Workshop

Seminar, Springfield, Illinois, November 6-8, 1962.

U.S. Department of Commerce, National Information Service, “An Appraisal of Tests and Standards for

the Evaluation of Electrical Insulating Fluids.” PB-253 110 (ERDA), May 14, 1976.

U.S. Department of Commerce, National Technical Information Service, “Polychlorinated Biphenyls and

the Environment,” Report No. ITF-PCB-72-1, Interdepartmental Task Force on PCB’s, Com.-72-

10419, Springfield, Va.: Dept. of Commerce.

5.7 AIR SWITCHES

5.7.1 General

This section deals with high-voltage air switches used in substations. Items discussed include applicable

national standards, types of air switches, various constructions of outdoor air switches, service conditions,

ratings, and tests.

The general function of an air switch is as stated in ANSI/IEEE Std. C37.100: “A switching device

designed to close and open one or more electrical circuits by means of guided separable contacts that

separate in air.” Air, at atmospheric pressure, is also the insulating medium between contacts in the open

position.

Many varieties of air switches have been developed to fulfill special user requirements. RUS IP 202-1,

“List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers,” contains both fully

accepted and conditionally accepted types of air switches and should be consulted whenever air switches

are required.

All varieties of air switches used in a cooperative’s substations need to generally conform to all applicable

national standards and guides. The principal standards and guides for air switches are the following:
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• ANSI Std. C29.1, “Test Methods for Electrical Power Insulators”

• ANSI Std. C29.8, “Wet-Process Porcelain Insulators (Apparatus, Cap and Pin Type)”

• ANSI Std. C29.9, “Wet-Process Porcelain Insulators (Apparatus, Post Type)”

• ANSI Std. C29.10, “Wet-Process Porcelain Insulators (Indoor Apparatus Type)”

• ANSI Std. C37.32, “Standard for Switchgear—High-Voltage Air Switches, Bus Supports, and

Switch Accessories—Schedules of Preferred Ratings, Manufacturing Specifications and

Application Guide”

• ANSI/IEEE Std. C37.100, “IEEE Standard Definitions for Power Switchgear”

• IEEE Std. C37.34, “Test Code for High-Voltage Air Switches”

• IEEE Std. C37.35, “Guide for the Application, Installation, Operation and Maintenance of

High-Voltage Air Disconnecting and Load-Interrupter Switches”

• NEMA Std. SG-6, “Power Switching Equipment”

5.7.2 Types of Air Switches

The main types of air switches are determined by and named according to their application. Standard

definitions, according to ANSI/IEEE Std. C37.100, describe their general functions.

5.7.2.1 Disconnecting or Isolating Switch (Disconnector, Isolator): “A mechanical switching device

used for changing the connections in a circuit, or for isolating a circuit or equipment from the source of

power.” This switch “is required to carry normal load current continuously and, also, abnormal or shortcircuit currents for short intervals as specified. It is also required to open or close circuits either when

negligible current is broken or made, or when no significant change in the voltage across the terminals of

each of the switch poles occurs.”

5.7.2.1.1 Typical Applications:

a. Circuit breaker isolation

b. Power transformer isolation

c. Voltage transformer disconnecting

d. Equipment bypassing

e. Bus sectionalizing

NOTE: Where the current to be broken or made is not negligible, a horn-gap switch (see Section 5.7.2.3)

should be used.

5.7.2.2 Grounding Switch: “A mechanical switching device by means of which a circuit or piece of

apparatus may be electrically connected to ground.” Grounding switches are often mounted on the jaw or

hinge end of disconnecting or horn-gap switches. See Figure 5-22.

5.7.2.2.1 Typical Applications:

a. To ground buses or circuits (for safe maintenance) after they are first isolated

b. To intentionally ground a circuit (using an automatic high-speed device) in order to activate a

remote protective relaying scheme

5.7.2.3 Horn-Gap Switch: “A switch provided with arcing horns.” See Figure 5-23.
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Figure 5-22: Horizontally Mounted Double Break Switch with Grounding Switch.

Courtesy of Tuley & Associates, Inc.

Figure 5-23: Horizontally Mounted Double-Break Switch. Note arcing horns and corona shields at blade

contact points. Courtesy of Tuley & Associates, Inc.
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5.7.2.3.1 Typical Application: To de-energize or energize a circuit that possesses some limited amount

of magnetic or capacitive energy, such as transformer exciting current or line charging current. The

arcing horns protect the main contacts during opening or closing and enhance the ability of the switch to

perform its task.

NOTE: Where the amount of current to be broken or made is not clearly within the switch’s capability,

consult the manufacturer or use an interrupter switch (see Section 5.7.2.4).

5.7.2.4 Interrupter Switch: “An air switch, equipped with an interrupter, for making or breaking

specified currents, or both.” “The nature of the current made or broken, or both, may be indicated by

suitable prefix, that is, load interrupter switch, fault interrupter switch, capacitor current interrupter

switch, etc.” Typical applications are indicated by the above-named prefixes. See Figure 5-24.

Figure 5-24: Horizontally Mounted Vertical-Break Interrupter Switch.

Courtesy of Tuley & Associates, Inc.

5.7.2.5 Selector Switch: “One arranged to permit connecting a conductor to any one of a number of

other conductors.” In substation applications, it is unlikely that more than two conductors would be

subject to selection.

5.7.2.5.1 Typical Applications:

a. To connect a potential device to either of two buses

b. To perform a joint disconnecting and grounding function

5.7.3 Various Constructions of Outdoor Air Switches

Outdoor air switches are constructed in many different styles or construction classifications. Preferred

standard ratings are listed in Tables 5-38, 5-39, and 5-40. A pictorial representation of each classification

is shown at the bottom of Table 5-39. The various constructions are described below and include

ANSI/IEEE Std. C37.100 definitions (in quotation marks) where appropriate.
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Table 5-38: Preferred Voltage Ratings for Station Class Outdoor Air Switches. Ref. ANSI Std. C37.32-

1996, Table 1. Reproduced with permission of the National Electrical Manufacturers Association.

Rated Withstand Voltage

Power Frequency

kV rms

Corona and Radio

Influences Test Voltages

Line Number

Rated

Maximum

Voltage

kV rms

Lightning

Impulse1

kV peak

Dry

1 Minute

Wet

10

Seconds

Test2

Voltage

kV rms

Limit of

RIV3

mV @ 1 MHz

(1) (2) (3) (4) (5) (6)

1 8.25 95 35 30 — —

2 15.5 110 50 45 — —

3 25.8 150 70 60 — —

4 38.0 200 95 80 — —

5 48.3 250 120 100 — —

6 72.5 250 120 100 — —

7 72.5 3504175 145 — —

8 121 350 175 145 77 500

9 121 450 235 190 77 500

10 121 5504280 230 77 500

11 145 350 175 145 92 500

12 145 450 235 190 92 500

13 145 550 280 230 92 500

14 145 6504335 275 92 500

15 169 450 235 190 107 500

16 169 550 280 230 107 500

17 169 650 335 275 107 500

18 169 7504385 315 107 500

19 2425) 550 280 230 154 500

20 2425) 650 335 275 154 500

21 2425) 750 385 315 154 500

22 2425) 9004465 385 154 500

23 2425) 1050 545 455 154 500

24 362 1050 545 455 230 500

25 362 13004610 525 230 500

26 550 1550 710 620 349 500

27 550 18004810 710 349 500

28 800 2050 940 830 508 750

NOTES:

(1) For switches rated 362 kV and higher, see table 2 [Table 5-39] for values of rated switching impulse

withstand voltages.

(2) The test voltages are 110% of the rated maximum line-to-neutral voltage. It is not necessary to retest

switches previously tested and acceptable at 105%.

(3) If equipment of any given rated maximum voltage is used on a circuit of a higher voltage rating, the

radio influence voltage limit and test voltage for the equipment shall be that corresponding to the rated

maximum voltage of the circuit.

(4) Modern arrester technology enables use of lower lightning impulse rated equipment in some

applications. The traditional values are shown in bold font.

(5)The switches listed in lines 19 through 28 are intended for application on systems effectively grounded

as defined in ANSI/ IEEE Std. 142.
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Table 5-39: Preferred Switching Impulse Withstand Voltage for Station Class

Outdoor Air Switches. Ref. ANSI Std. C37.32-1996, Table 2.

Reproduced with permission of the National Electrical Manufacturers Association.

Switching Impulse Withstand Voltage kV

Peak

Rated

Maximum

Voltage

kV rms

Rated Lightning

Impulse

kV

Peak

To

Ground1

Across

Open Gap2

Line

Number

(from table 1

[Table 5-38]) (1) (2) (3) (4)

24 362 1050 750 655 + (295)

25 362 1300 885 825 + (295)

26 550 1550 1050 880 + (450)

27 550 1800 1150 1000 + (450)

28 800 2050 1300 1000 + (650)

NOTES:

(1) Line-to-ground insulation strength is based upon 97.7 percent probability of withstand where the

standard deviation is 6 percent. See ANSI Std. C37.34, 4.4.7.

(2) Values in parenthesis are 60 Hz bias voltages expressed in kVp units (column 1 voltage * 2 / 3 ).

The summation of this opposite polarity bias voltage and the associated open gap switching impulse

voltage is equal to a 97.7 percent probability of line-to-ground flashover (CFO + 2). See C37.34,

4.4.8.

CONSTRUCTION CLASSIFICATIONS

Ref. ANSI Std. C37.32 – 1996, Annex B, Figure B–1. Reproduced with permission of the National

Electrical Manufacturers Association.
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Table 5-40: Preferred Continuous and Withstand Currents for Station Class

Outdoor Air Switches. Ref. ANSI Std. C37.32-1996, Table 3.

Reproduced with permission of the National Electrical Manufacturers Association.

Withstand Currents

Line

Number

Continuous

Current

Rating

Amps

(1)

Short-Time

Withstand

(Symmetrical)

kA

(2)

Peak

Withstand

kA

(3)

1 600 25 65

2 1200 38 99

3 1600 44 114

4 2000 44 114

5 2000 63 164

6 3000 63 164

7 3000 75 195

8 4000 75 195

NOTES:

(1) The ratio of the peak withstand current to short-time (symmetrical) withstand current is 2.6.

(2) Rated duration of the short-time (symmetrical) withstand current is 3 seconds with allowable I2

t

variations given in IEEE C37.34.

(3) Rated duration of the peak withstand current test is 167 milliseconds.

(4) Peak withstand current (kA) ≅ 1.625 times the rms asymmetrical momentary current (kA). Switches

previously rated at 40, 61, 70, 100, and 120 kA rms asymmetrical momentary are closely equivalent

to the above peak withstand current ratings and do not require retesting.

5.7.3.1 Vertical Break Switch (Construction Classification A): “One in which the travel of the blade

is in a plane perpendicular to the plane of the mounting base. The blade in the closed position is parallel

to the mounting base.” The hinge end includes two insulators, one of which is caused to rotate by the

operating mechanism and thereby open and close the blade. See Figure 5-25.

Figure 5.-25: Vertically Mounted Vertical-Break Switch. Courtesy of Tuley & Associates, Inc.
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5.7.3.2 Double Break Switch (Construction Classification B): “One that opens a conductor of a

circuit at two points.” The center insulator stack rotates to accomplish the opening and closing operation.

See Figure 5-23.

5.7.3.3 Tilting-Insulator Switch (Construction Classifications C & F): “One in which the opening

and closing travel of the blade is accomplished by a tilting movement of one or more of the insulators

supporting the conducting parts of the switch.” This type of switch is seldom used today. However, this

switch is still in service on many existing installations. It is included here since it will be necessary to

modify or replace such switches on occasion. See Figure 5-26.

Figure 5-26: Tilting Insulator Switch. Courtesy of Kearney.

5.7.3.4 Side-Break Switch (Construction Classification D): “One in which the travel of the blade is

in a plane parallel to the base of the switch.” The hinge-end insulator rotates to accomplish the opening

and closing operation. See Figure 5-27.

5.7.3.5 Center-Break Switch (Construction Classification E): One in which travel of the blade is in

a plane parallel to the base of the switch and that opens in the center at only one point. Both insulators

rotate to accomplish the opening and closing operation. See Figure 5-28.

5.7.3.6 Grounding Switch (Construction Classification G): As noted in Section 5.7.2.2, “a

mechanical switching device by means of which a circuit or piece of apparatus may be electrically

connected to ground.” The pictorial representation in Table 5-39 shows a type where an insulated blade,

connected to a bus or a piece of equipment, is made to contact ground. Some types use a normally

grounded blade, which is made to contact the bus or equipment to be grounded. See Figure 5-22.
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Figure 5-27: Single Side-Break Switch. Courtesy of Southern States, Inc.

Figure 5-28: Underhung Center-Break V-Switch. Courtesy of Tuley & Associates, Inc.

5.7.3.7 Hook Stick Switch (Construction Classification H): One that is opened manually by means

of a switch stick. Both insulators remain stationary when the blade, hinged at one end, is unlatched and

opened or closed by the switch stick. These are single-pole (single-phase) switches. See Figure 5-29.

5.7.3.8 Vertical Reach Switch (Construction Classification J): “One in which the stationary contact

is supported by a structure separate from the hinge mounting base. The blade in the closed position is

perpendicular to the hinge mounting base.” See Figure 5-30.
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Figure 5-29: Hook Stick Switches on Structure at Termination of Bus from Transformer

(Coffeyville, Kansas)

Figure 5-30: Vertical Reach Switch. Courtesy of Southern States, Inc.
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5.7.4 Usual Service Conditions

The ratings of all high-voltage air switches covered by the standards are based on the following.

5.7.4.1 Temperature: Ambient temperature of cooling air over the switch is within the range of -30°C

to +40°C for non-enclosed indoor or outdoor switches. Ambient temperature of cooling air over the

switch does not exceed 55°C for enclosed indoor or outdoor switches. Maximum ambient temperature

outside the enclosure does not exceed 40°C.

5.7.4.2 Altitude: Altitude does not exceed 1000 meters (3300 feet). Correction factors should be

applied above 1000 meters as shown in Table 5-41.

Table 5-41: Altitude Correction Factors for High-Voltage Air

Switches. Ref. ANSI/IEEE Std. C37.30–1992, Table 1.

Copyright © 1992. IEEE. All rights reserved.

Altitude Correction Factor

To Be Applied to:

Rated

Withstand Current

Altitude Voltage Rating*

Feet Meters Col.1 Col. 2

3300 1000 1.00 1.00

4000 1200 0.98 0.995

5000 1500 0.95 0.99

6000 1800 0.92 0.985

7000 2100 0.89 0.98

8000 2400 0.86 0.97

9000 2700 0.83 0.965

10000 3000 0.80 0.96

12000 3600 0.75 0.95

14000 4200 0.70 0.935

16000 4800 0.65 0.925

18000 5400 0.61 0.91

20000 6000 0.56 0.90

NOTE 1: This table is being reviewed. Check later revisions of standard for values.

* For maximum ambient of 40°C for non-enclosed switches

and 40°C outside the enclosure for enclosed switches.

5.7.5 Ratings

5.7.5.1 General: The various ratings covered by the ANSI Standards for the several types of air break

switches are indicated by an “X” in Table 5-42. All these ratings are defined in ANSI/IEEE Std.

C37.100. However, the main rating definitions applicable to “disconnecting switches” will be repeated

here for convenience since this is the most common air switch used in substations. For the most part, the

ratings repeated here also apply to the other switch types.
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Table 5-42: Switch Ratings and Required Tests. Ref. IEEE C37.30-1997, Table 1.

Copyright © 1997. IEEE. All rights reserved.

Disconnecting

Switch

Interrupter

Switch

FaultInitiating

Switch

Grounding

Switch Switch

Rating

Column 1 Column 2 Column 3 Column 4

Rated power frequency X X X X

Rated maximum voltage X X X X

Rated continuous current X X — —

Rated dielectric withstand voltages X X X X

 Rated lightning-impulse withstand (BIL) X X X X

 Rated switching-impulse withstand (for rated

 maximum voltage of 362 kV and above) X X X X

 Rated power frequency dry withstand X X X X

 Rated power frequency wet withstand (outdoor) X X X X

 Rated dew power frequency withstand (indoor) X X X X

Rated peak-withstand current X X O X

Rated short-time (symmetrical) withstand current X X O X

Rated short-time (symmetrical) withstand current

duration X X O X

Rated mechanical operations X X — X

Rated mechanical terminal load X X X X

Rated ice-break ability – manual (outdoor) X X X X

Rated ice-break ability – power: single attempt

opening and closing (outdoor) X X X X

Rated ice-break ability – power: single attempt

opening, multiple attempt closing (outdoor) X X — X

Rated load-making current O X — X

Rated fault-making current — X O

Rated switching parameters a

Rated capacitance-switching overvoltage ratioa — X

b — —

Rated minimum differential-capacitance voltagea — — —

Rated maximum differential-capacitance voltagea — X

b — —

Rated load-interrupting current and expected

switching endurancea — O

c — —

Rated unload transformer interrupting current and

expected switching endurancea — O

c — —

Rated single-capacitance interrupting current and

expected switching endurancea — O

c — —

Rated parallel-connected capacitance-switching

current and expected switching endurancea — O

c — —

NOTES: ”X” indicates required rating; “O” indicates optional rating; “—” indicates not applicable.

a

 Relates to interrupter switches and will be superseded by IEEE PC37.39 when it is completed and

approved.

b Required if the interrupter switch has capacitance-switching ratings.

c

 At least one current-interrupting rating is required for interrupter switches.
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5.7.5.2 Disconnecting Switch Ratings

5.7.5.2.1 Rated Voltage: Rated voltage “is the highest nominal system voltage on which it is intended

to be applied.”

5.7.5.2.2 Rated Maximum Voltage : Rated maximum voltage “is the highest rms voltage at which the

device is designed to operate.”

5.7.5.2.3 Rated Continuous Current: Rated continuous current “is the maximum direct current, or rms

current, in amperes at rated frequency which it will carry continuously without exceeding the limit of

observable temperature rise.”

NOTE: Allowable continuous current at a “specific ambient temperature is the maximum direct or

alternating current in amperes, rms at rated frequency which it will carry without exceeding the allowable

temperature for any of its parts as listed in Column 1” of Table 5-43.

The allowable continuous current may be determined using Equation 5-5:

Equation 5-5

2

1

max















 −

=

r

A

A R

I I

q

q q

Where:

θA = Ambient temperature (°C)

IA = Allowable continuous current at θA

IR = Rated continuous current

θmax = Allowable temperature of switch part from Table 5-43

θr = Limit of observable temperature rise (°C) at rated current of switch part from Table 5-43

The values of θr in Table 5-43 have been selected (when the switch is tested in accordance with Section 6

of IEEE Std. C37.34) to maintain a loadability of 1.22 at 25°C (77°F) where:

Loadability of a non-enclosed air switch is the ratio of allowable continuous current at

25°C (77°F) ambient temperature to rated current. The loadability of an enclosed air

switch is the ratio of allowable continuous current at 40°C (104°F) inside ambient

temperature to rated current.

Users in colder climates and those with maximum load currents, known to occur during ambients lower

than 40°C (104°F), should carefully consider the possible cost benefits from taking advantage of

allowable continuous currents when selecting the continuous current rating of any air break switch. In

such applications, a lower continuous current rating may be sufficient, compared to a rating based strictly

on the maximum direct, or rms alternating current, of the circuit in question.
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Table 5-43: Temperature Limitations for Air Switches. IEEE Std. C37.30–1997, Table 2.

Copyright © 1997. IEEE. All rights reserved.

Nonenclosed Indoor and

Outdoor Switches

Enclosed Indoor and Outdoor

Switches

Allowable

Max

Temperature,

θmax

(°C)

Limit of

Observable

Temperature

Rise and Rated

Current (θr)

(°C)

(see Note 1)

Switch Part

Class

Designation

Limit of

Observable

Temperature

Rise at Rated

Current, θr

(°C)

Switch Part

Class

Designation

Col. 1 Col. 2 Col. 3 Col. 4 Col. 5

(1) Contacts in air (see Note 2)

 (a) Copper or copper alloy 75 33 BO2 20 QO33

 (b) Copper or copper alloy to silver or silver alloy, or

 equivalent 90 43 DO4 33 RO4

 (c) Silver, silver alloy, or equivalent 105 53 FO6 43 TO6

 (d) Other (see Note 3) — — — — —

(2) Conducting mechanical joints

 (a) Copper or aluminum 90 43 DO4 33 RO4

 (b) Silver, silver alloy, or equivalent 105 67 FO6 57 TO6

 (c) Other (see Note 3) — — — — —

(3) Switch terminals with bolted connections 90 43 DO4 33 RO4

(4) Welded or brazed joints or equivalent 105 53 FO6 43 TO6

(5) Other current-carrying parts

 (a) Copper or copper alloy castings 105 53 FO6 43 TO6

 (b) Hard drawn copper parts (see Note 4) 80 37 CO3 25 PO22

 (c) Heat treated aluminum alloy parts 105 53 FO6 43 TO6

 (d) Woven wire flexible connectors 75 33 BO2 20 QO33

 (e) Other materials (see Note 3) — — — — —

(6) Insulator caps and pins and bushing caps 110 57 GO7 47 UO7

(7) Current-carrying parts in contact with insulation

materials

(a) Insulation Class 90°C

(b) Insulation Class 105°C

(c) Insulation Class 130°C

(d) Insulation Class 155°C

(e) Insulation Class 180°C

(f) Insulation Class 220°C

(g) Oil (see Note 5)

(h) SF6

90

105

130

155

180

220

90

350

43

53

70

87

103

130

43

307

CO3

EO5

HO8

IO9

JO10

KO11

DO4

—

33

43

60

77

93

120

33

297

PO22

SO5

VO8

WO9

XO10

YO11

RO4

—

(8) Nonenergizable parts subjected to contact by personnel

(a) Handled by operator (see Note 6)

(b) Accessible to operator (see Note 6)

(c) Not accessible to operator (see Note 7)

50

70

—

10

30

—

—

—

—

10

30

—

—

—

—

(9) Entire switch in accordance with IEEE C37.30-1992

(a) Outdoor

(b) Indoor

70

85

30

—

AO1

—

—

30

—

NO1
Bulletin 1724E-300

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NOTES to Table 2:

(1) The limit of observable temperature rise listed in this column is suitable for use in rating switches for

application in enclosures of IEEE C37.20.2–1993 and IEEE C37.20.3-1987, if the corresponding

allowable maximum temperature listed in column 1 is not exceeded when in the enclosure. These

temperature rises are chosen to give a loadability of 1.22 at 23°C.

(2) Contacts as used here include: (a) stationary and moving contacts that engage and disengage, and

(b) contacts that have relative movement but remain engaged.

(3) Other materials may become available for contacts, conducting mechanical joints, and other currentcarrying parts that have a different allowable maximum temperature, θmax. Their limit of observable

temperature rise at rated continuous current, θr, shall be related to their θmax in accordance with 5.4.

(4) If annealing will not impair switch operation or reduce ability to meet any of the ratings, 105°C may be

used for θmax and the corresponding increase in θr as determined in 5.4.

(5) The top oil (upper layer) temperature shall not exceed 80°C total. The 90°C value refers to the

hottest-spot temperature of parts where they contact the oil.

(6) It is assumed that any parts handled by or accessible to an operator will be in ambient air not to

exceed 40°C.

(7) The maximum temperature of any nonenergizable part not accessible to the operator shall not

exceed a temperature that will necessitate maintenance or replacement of parts during the life of the

switch.

5.7.5.2.4 Rated Short-Time Current (Momentary and Three Second)

5.7.5.2.4.1 Rated momentary current “is the rms total current which the switch shall be required to

carry for at least one cycle. The current shall be the rms value, including the direct-current component,

during the maximum cycle as determined from the envelope of the current wave, and the test period shall

be at least ten cycles.”

5.7.5.2.4.2 Rated three-second current is the rms total current, including any direct current

component, that the switch shall be required to carry for three seconds.

5.7.5.2.5 Rated Withstand Voltage : Rated withstand voltage “shall be the voltage which the device has

to withstand without flashover or other electric failure when voltage is applied under specified

conditions.” The standard low-frequency wet and dry and 1.2 x 50 microsecond impulse withstand

voltages are listed in ANSI Std. C37.32.

5.7.5.2.6 Preferred Ratings: The preferred ratings of voltage, continuous current, short-time current

ratings, dielectric withstand voltages, and radio influence test voltages of various constructions of outdoor

air switches (at 60 Hz) shall be in accordance with Tables 5-38, 5-39, and 5-40.

5.7.6 Other Requirements

5.7.6.1 Insulators: Insulators used need to have sufficient strength to withstand the magnetic forces

produced by the rated momentary current ratings specified in Table 5-40.

An approximation of the electromagnetic force exerted between two current-carrying conductors is given

by Equation 5-6 (from ANSI Std. C37.32):
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Equation 5-6

Where:

F = Pounds per foot of conductor

M = Multiplying factor (determined from Table 5-44)

I = Short-circuit maximum peak current in amperes in accordance with Table 5-44

S = Spacing between centerlines of conductors in inches

The force calculated from the above operation will, in most cases, be conservative, tending to compensate

for the neglect of resonant forces. It should, therefore, be reasonably accurate for the majority of practical

situations.

Table 5-44: Multiplying Factor (M) for Calculation of Electromagnetic Forces.

Ref. ANSI Std. C37.32–1996, Annex A.3.2.

Reproduced with permission of the National Electrical Manufacturers Association.

Circuit Amperes (I) Expressed as Multiplying Factor (M)

dc maximum peak 1.0

ac, 3-phase maximum peak 0.866

ac, 3-phase rms asymmetrical (0.866 x 1.632) = 2.3

ac, 3-phase rms symmetrical (0.866 x 2.822) = 6.9

1 phase of 3-phase or 1-phase maximum peak 1.0

1 phase of 3-phase or 1-phase rms asymmetrical (1.632) = 2.66

1 phase of 3-phase or 1-phase rms symmetrical (2.822) = 8.0

5.7.6.2 Terminal Loadings: Terminal pad loadings should be in accordance with Table 5-45.

The arrangement of bolt hole centerlines in terminal pads should be in accordance with Figure 5-31.

Holes should accommodate bolts 1⁄2 inch (12.7 mm) in diameter.

1. Two or more interleaved 4-hole pad configurations can be used as shown in Figure 5-31(b) (of

ANSI Std. C37.32-1996).

2. All dimensions are in inches and millimeters.

















×

×

= 7

2

10

5.4

S

I

F M
Bulletin 1724E-300

Page 314

Table 5-45: Terminal Loadings for High-Voltage Switches. Ref. ANSI Std. C37.32-1996, Table 2.

Reproduced with permission of the National Electrical Manufacturers Association.

Line

Number

Maximum

voltage kV

Current rating

amps

F1 and F2

 lbs (N)

F3

 lbs (N)

F4

 lbs (N)

(1) (2) (3) (4) (5)

1 4.8–72.5 200-1200 90 (400) 30 (130) 30 (130)

2 >2000 90 (400) 30 (130) 30 (130)

3 121–169 600–1600 120 (530) 40 (180) 110 (490)

4 >2000 120 (530) 40 (180) 250 (1110)

5 242–362 1200–1600 180 (800) 60 (270) 375 (1670)

6 >2000 230 (1020) 75 (330) 685 (3040)

7 >500 All 450 (2000) 150 (670) 750 (3330)

NOTES:

(1) Terminal pad loading F1, F2, F3, and F4 incorporate considerations for typical weights of connected

bus conductors having ice and wind loads, expansion loads, and limited moment forces. It is

recommended that the manufacturer be consulted on forces that exceed those given in the table.

These higher forces may be due to long bus spans rigidly connected to switches, extra high short

circuit current forces, bus spans other than aluminum tube conductors, and other forces not

considered.

(2) These loadings were derived for the mechanical operations requirement of IEEE C37.34, Clause

11 and do not necessarily represent the mechanical loading limit on terminals. Consult the

manufacturer when actual valves are needed.

(3) At 242 kV and above, F4 forces may be reduced by 40% for switches with hinged or pivoting-type

terminal pads.
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Figure 5-31: Arrangement of Bolt Hole Centerlines in Terminal Pads. Ref. ANSI Std. C37.32-1996,

Figure 1. Reproduced with permission of the National Electrical Manufacturers Association.
Bulletin 1724E-300

Page 316

5.7.6.3 Outdoor Air Switch Break Length: The length of break of outdoor air switches, when in the

full open position, shall be such that the open gap or gaps will withstand a test voltage that is 10 percent

in excess of the low-frequency impulse and dry withstand test voltages given in Table 5-38.

5.7.6.4 Break Distances and Spacing: The minimum metal-to-metal single-pole break distances

and the single-pole centerline-to-centerline spacing of insulator columns needs to be as specified in

Table 5-46 (see page 317 of this bulletin).

5.7.6.5 Base Mounting Holes: Base mounting holes for outdoor air switches shall be as specified in

Table 5-47.

Table 5-47: Station-Class Outdoor Air Switches Preferred Mounting Hole Spacing

for 600-, 1200-, and 1600-Ampere Switches. Ref. ANSI Std. C37.32-1996, Table 7.

Reproduced with permission of the National Electrical Manufacturers Association.

Hook stick Single side break Vertical break Rated

Max.

Voltage

kV rms

A

In. (mm)

B

In. (mm)

A

In. (mm)

B

Inches (mm)

A

In. (mm)

B

In. (mm) Line

No. (1) (2) (3) (4) (5) (6) (7)

1 8.25 18 (457) 2 or 7 (50.8 or 178) 24 (610) 3 or 7 (76.2 or 178) 36 (914) 3 or 7 (76.2 or 178)

2 15.5 21 (533) 2 or 7 24 (610) 3 or 7 36 (914) 3 or 7

3 25.8 24 (610) 2 or 7 27 (686) 3 or 7 39 (991) 3 or 7

4 38.0 30 (762) 2 or 7 33 (838) 3 or 8-1/4 (76.2 or 210) 48 (1220) 3 or 8-1/4 (76.2 or 210)

5 48.3 39 (991) 3 or 8-1/4 (76.2 or 210) 39 (991) 3 or 8-1/4 54 (1370) 3 or 8-1/4

6 72.5 51 (1290) 3 or 8-1/4 51 (1290) 3 or 8-1/4 69 (1750) 3 or 8-1/4

7 121 66 (1680) 3 or 8-1/4 72 (1830) 8-1/4 (210) 87 (2210) 8-1/4 (210)

8 145 78 (1980) 3 or 8-1/4 84 (2130) 8-1/4 99 (2510) 8-1/4

9 169 90 (2290) 8-1/4 (210) 96 (2440) 8-1/4 111 (2820) 8-1/4

NOTES:

(1) “A” is the dimension along the length of the base and “B” is the dimension along the width of the base

in inches.

(2) Dimensions for switches above 169 kV have not yet been established.

(3) Millimeter values approximate 25.4 mm per inch.

5.7.6.6 Phase Spacing: Phase spacing (pole spacing), centerline-to-centerline, for outdoor air switches

needs to be as specified in Table 5-48.
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Table 5-46: Station-Class Outdoor Air Switch—Pole Unit Dimensions. Ref. ANSI Std. C37.32-1996, Table 6.

Reproduced with permission of the National Electrical Manufacturers Association.

Length of Break Minimum

Metal-to-Metal1

Insulator Centerline-to-Centerline Phase Spacing

Inches Minimum1 (mm)

Single Break

Distance

Double Break

Distance

Single Break

Insulator Strength

Double Break

Insulator Strength

Rated

Maximum

Voltage

kV rms

Rated

Lightning

Impulse

Withstand

Voltage

Line kV Peak Inches (mm) Inches (mm) Standard High Standard High

Nos. (1) (2) (3) (4) (5) (6) (7) (8)

1 8.3 95 7 (178) -- 12 (305) 15 (381) -- --

2 15.5 110 10 (254) -- 15 (381) 18 (457) -- --

3 25.8 150 12 (305) -- 18 (457) 21 (533) -- --

4 38.0 200 18 (457) 12 (305) 24 (610) 27 (686) 18 (457) 21 (533)

5 48.3 250 22 (559) 15 (381) 30 (762) 33 (838) 23 (585) 24 (610)

6 72.5 250 22 (559) 15 (381) 30 (762) 33 (838) 23 (585) 24 (616)

7 72.5 350 32 (813) 22 (559) 42 (1067) 45 (1140) 30 (762) 34 (864)

8 121 350 32 (813) 22 (559) 42 (1067) 45 (1140) 30 (762) 34 (864)

9 121 450 See Note 2 See Note 2 51 (1295) 54 (1370) 35 (889) —

10 121 550 50 (1270) 32 (813) 60 (1520) — 42 (1067) —

11 145 350 32 (813) 22 (559) 42 (1067) 45 (1140) 30 (762) 34 (864)

12 145 450 See Note 2 See Note 2 51 (1295) 54 (1370) 35 (889) —

13 145 550 50 (1270) 32 (813) 60 (1520) — 42 (1067) —

14 145 650 60 (1520) 38 (965) 72 (1830) — 48 (1220) —

15 169 450 See Note 2 See Note 2 51 (1295) 54 (1370) 35 (889) —

16 169 550 50 (1270) 32 (813) 60 (1520) — 42 (1067) —

17 169 650 60 (1520) 38 (965) 72 (1830) — 48 (1220) —

18 169 750 68 (1730) 44 (1120) 84 (2130) — 54 (1370) —

19 242 550 50 (1270) 32 (813) 60 (1520) — 42 (1067) —

20 242 650 60 (1520) 38 (965) 72 (1830) — 48 (1220) —

21 242 750 68 (1730) 44 (1120) 84 (2130) — 54 (1370) —

22 242 900 84 (2130) 50 (1270) 96 (2440) — 68 (1730) —

23 242 1050 104 (2640) 57 (1450) 116 (2950) — 75 (1900) —

24 362 1050 104 (2640) 57 (1450) 116 (2950) — 75 (1900) —

25 362 1300 120 (3050) 66 (1680) 132 (3350) — 84 (2130) —

26 550 1550 See Note 2 — See Note 2 — — —

27 550 1800 See Note 2 — See Note 2 — — —

28 800 2050 — — — — — —

NOTES:

1. The design of some switches may be such that the minimum metal-to-metal distance and the centerline-to-centerline spacing conflict.

Where this occurs, the minimum metal-to-metal distance should be used. Minimum metal-to-metal distances may be modified provided

proof of performance is substantiated by dielectric tests.

2. Values have not yet been established.
Bulletin 1724E-300

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Table 5-48: Phase Spacing and Ground Clearance for Station-Class Outdoor Air Switches and Bus Supports. Ref. ANSI Std. C37.32–1996,

Table 5. Reproduced with permission of the National Electrical Manufacturers Association.

Ground Clearance3 Centerline-to-Centerline Phase Spacing4

Rated

Max.

Voltage

Rated

Lightning

Withstand

Voltage1

Min. Metal-to-Metal

Distance Disconnecting

Switches, Bus Supports,

and Rigid Conductors2

Recommended Minimum

Vertical Break

Disconnecting Switches

and Bus Supports

Side Break

(Horizontal Break)

Disconnecting

Switches

All Horn Gap

Switches

(Vertical and Side

Break)

Line kV rms kV Peak inches mm inches mm inches mm inches mm inches mm inches mm

No. (1) (2) (3) (4) (5) (6) (7) (8)

1 8.25 95 7 178 7.5 191 6 152 18 457 30 762 36 914

2 15.5 110 12 305 10 254 7 178 24 610 30 762 36 914

3 25.8 150 15 381 12 305 10 254 30 762 36 914 48 1220

4 38.0 200 18 457 15 381 13 330 36 914 48 1220 60 1520

5 48.3 250 21 533 18 457 17 432 48 1220 60 1520 72 1830

6 72.5 250 21 533 18 457 17 432 48 1220 60 1520 72 1830

7 72.5 350 31 787 29 737 25 635 60 1520 72 1830 84 2130

8 121 350 31 787 29 737 25 635 60 1520 72 1830 84 2130

9 121 450 44 1118 39 991 34 846 72 1830 91 2310 103 2620

10 121 550 53 1350 47 1193 42 1067 84 2130 108 2740 120 3050

11 145 350 31 787 29 737 25 635 60 1520 72 1830 84 2130

12 145 450 44 1118 39 991 34 846 72 1830 91 2310 103 2620

13 145 550 53 1350 47 1193 42 1067 84 2130 108 2740 120 3050

14 145 650 63 1600 52.5 1333 50 1270 96 2440 132 3350 144 3660

15 169 450 44 1118 39 991 34 846 72 1830 91 2310 103 2620

16 169 550 53 1350 47 1193 42 1067 84 2130 108 2740 120 3050

17 169 650 63 1600 52.5 1333 50 1270 96 2440 132 3350 144 3660

18 169 750 72 1830 61.5 1562 58 1473 108 2740 156 3960 168 4270

19 242 550 53 1350 47 1193 42 1067 84 2130 108 2740 120 3050

20 242 650 63 1600 52.5 1333 50 1270 96 2440 132 3350 144 3660

21 242 750 72 1830 61.5 1562 58 1473 108 2740 156 3960 168 4270

22 242 900 89 2260 76 1930 71 1803 132 3350 192 4870 192 4870

23 242 1050 105 2670 90.5 2299 83 2108 156 3960 216 5500 216 5500

24 362 1050 105 2670 90.5 2299 84 2134 156 3960 216 5500 216 5500

25 362 1300 119 3020 106 2692 104 2642 174 4430 See Note 5 240 6100

26 550 1550 See Note 5 See Note 5 124 3150 See Note 5 See Note 5 300 7620

27 550 1800 See Note 5 See Note 5 144 3658 See Note 5 See Note 5 324 8230

28 800 2050 See Note 5 See Note 5 166 4216 See Note 5 See Note 5 600 15240

(1) Close lightning arrester coordination may allow lower lightning impulse values. Traditional values shown in bold font.

(2) Minimum metal-to-metal distance may be modified providing proof of performance is substantiated by dielectric test.

(3) Ground clearances for switches with voltages 362 kV and above are based on switching surge voltage levels. Refer to bibliography,

Annex C [of ANSI Std. C37.32-1996].

(4) The phase spacings in columns 6, 7, and 8 are recommended values. Overall width of switch and bus support energized parts, angle of

opening of side-break switches, etc., may allow a reduction in phase spacing dependent upon voltage concentration on sharp projections.

Resultant metal-to-metal distances between phase energized parts should not be less than that shown in Column 3.

(5) Values not yet established.
Bulletin 1724E-300

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5.7.6.7 Ratings and Requirements for Switches: Preferred ratings and other requirements for indoor

air switches, grounding switches, fault initiating switches and load interrupter switches are listed in ANSI

Std. C37.32, Sections 5 through 8, respectively. Tables 5-49 through 5-51 list ratings and requirements

applicable to indoor air switches and grounding switches.

Table 5-49: Preferred Ratings for Indoor Air Switches. Ref. ANSI Std. C37.32-1996, Table 12.

Reproduced with permission of the National Electrical Manufacturers Association.

Rated Withstand Voltage Continuous Current Rating (Amperes, rms)

Power Frequency

kV rms

200 400 600 1200 2000 3000 4000 5000 6000 Rated

Max.

Voltage

kV rms

Impulse

Lightning

kV Peak Dew 10

Sec.

Dry 1

Min. Short-time (symmetrical) current ratings, thousands of amperes rms (1)

Line

No. (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13)

1 4.8 60 15 19 12.5 12.5 25 38 50 63 -- -- --

2 8.25 75 24 26 12.5 12.5 25 38 50 63 75 100 125

3 15.0 95 26 36 12.5 12.5 25 38 50 63 75 100 125

4 15.5 110 30 50 12.5 12.5 25 38 50 63 75 100 125

5 25.8 125 40 60 — 12.5 25 38 50 63 75 100 —

6 38.0 150 — 80 — 12.5 25 38 50 63 75 — —

(1) Short-time current ratings include a momentary current rating and a 3-second current rating, based on the test conditions

described in Section 5 of ANSI/ IEEE C37.34. Divide the momentary current rating by 1.6 to obtain the 3-second ratings.

NOTES:

(1) Withstand current ratings include a peak withstand current rating as well as a short-time (symmetrical)

withstand current rating as shown.

(2) The ratio of the peak withstand current to short-time (symmetrical) withstand current is 2.6.

(3) Rated duration of the short-time (symmetrical) withstand current is three (3) seconds with allowable I2

t

variations given in IEEE C37.34.

(4) Rated duration of the peak withstand current test is 167 milliseconds.
Bulletin 1724E-300

Page 320

Table 5-50: Indoor Air Switches and Bus Supports—Phase Spacing and Length of Break.

Ref. ANSI Std. C37.32-1996, Table 13.

Reproduced with permission of the National Electrical Manufacturers Association.

Line

No.

Rated Max.

Voltage kV

rms

Phase Spacing Minimum Metal-toMetal Clearance Disconnecting Air

Switches and Bus Supports Inches1)

Length of Break Minimum

Metal-to-Metal Single-Break

Distances Inches (2)

(1) (2)

 Inches (mm)

(3)

 Inches (mm)

1 4.8 4- 1/2 (114) 4-1/2 (114)

2 8.25 6 (152) 6 (152)

3 15.0 7-1/2 (190) 7-1/2 (190)

4 15.5 9 (229) 9 (229)

5 25.8 13 (330) 13 (330)

6 38.0 18 (457) 18 (457)

NOTE – Millimeter values approximate 25.4 mm per inch.

(1) Barriers may be used to provide additional safety during operation by preventing accidental contact

with live parts. The provision of adequate insulating barriers may allow a modification of these

clearances. These minimum clearances may be modified provided proof of performance is

substantiated by dielectric test (with due consideration to the effects of electromagnetic forces) in

accordance with the values shown in columns 2 and 4 of table 12. When indoor switches are mounted

in equipment covered by other standards, minimum clearances may be modified by such standards.

(2) Minimum metal-to-metal distances may be modified from the values listed above provided proof of

performance is substantiated by the dielectric test in accordance with Clause 4 of IEEE C37.34.
Bulletin 1724E-300

Page 321

Table 5-51: Grounding Switch Electrical Clearance.

Ref. ANSI Std. C37.32-1996, Table 14.

Reproduced with permission of the National Electrical Manufacturers Association.

Line

No.

Rated

Maximum Voltage

kV rms

Rated Lightning Impulse

 Withstand Voltage

kV Peak

Minimum Gap –

Ground Switches

to Live Parts

inches mm

(1) (2) (3)

INDOOR

1 4.8 60 2.0 50.8

2 8.25 75 2.0 50.8

3 15.0 95 2.0 50.8

4 15.5 110 2.0 50.8

5 25.8 125 3.0 76.2

6 38.0 150 4.0 102

DISTRIBUTION CLASS OUTDOOR

7 8.25 75 2.0 50.8

8 15.0 95 2.0 50.8

9 27.0 125 3.0 76.2

10 38.0 150 4.0 102

STATION CLASS OUTDOOR

11 8.25 95 2.0 50.8

12 15.5 110 2.0 50.8

13 25.8 150 4.0 102

14 38.0 200 6.0 152

15 48.3 250 9.5 241

16 72.5 250 9.5 241

17 72.5 350 14 367

18 121 350 14 367

19 121 450 18 457

20 121 550 22 559

21 145 350 14 367

22 145 450 18 457

23 145 550 22 559

24 145 650 27 686

25 169 450 18 457

26 169 550 22 559

27 169 650 27 686

28 169 750 31 787

29 242 550 22 559

30 242 650 27 686

31 242 750 31 787

32 242 900 38 965

33 242 1050 44 1118

34 362 1050 47 1194

35 362 1300 50 1270

36 550 1550 75 1905

37 550 1800 85 2159

38 800 2050 112 2845

NOTE – These gap distances are not a requirement for grounding blades that

operate in a plane perpendicular to the main switch base.
Bulletin 1724E-300

Page 322

5.7.6.8 Outdoor Air Switch Hook Dimensions: Outdoor air switch hook dimensions shall be in

accordance with Figure 5-32.

NOTES:

1. All dimensions are in inches (millimeter values are approximate).

2. Dimensions that are not shown are optional.

Figure 5-32: Outdoor Air Switch Hook Dimensions. Ref. ANSI Std. C37.32-1996, Figure 2.

Reproduced with permission of the National Electrical Manufacturers Association.

5.7.7 Mounting Considerations

5.7.7.1 Supports: Air switches should be mounted on supports strong enough to ensure that current

carrying contacts mate properly when opened and closed, since considerable reaction forces are exerted

on the supports during operation.

5.7.7.2 Orientation: Whenever possible, air switches should be oriented so that the blade is dead when

the switch is open.

5.7.7.3 Mounting Arrangement: The intended mounting arrangement of air break switches should be

made known to the manufacturer so that the insulators will be properly assembled.
Bulletin 1724E-300

Page 323

5.7.8 References

ANSI Std. C29.1, “Test Methods for Electrical Power Insulators.”

ANSI Std. C29.8, “Wet-Process Porcelain Insulators (Apparatus, Cap and Pin Type).”

ANSI Std. C29.9, “Wet-Process Porcelain Insulators (Apparatus, Post Type).”

ANSI Std. 29.10, “Wet-Process Porcelain Insulators (Indoor Apparatus Type).”

ANSI Std. C37.32, “Standard for Switchgear—High-Voltage Air Switches, Bus Supports, and Switch

Accessories-Schedules of Preferred Ratings, Manufacturing Specifications and Application Guide.”

ANSI Std. C37.33, “High-Voltage Air Switches—Rated Control Voltages and Their Ranges.”

ANSI/IEEE Std. C37.100, “Standard Definitions for Power Switchgear.”

ANSI/IEEE Std. 142, “IEEE Recommended Practice for Grounding of Industrial and Commercial Power

Systems (IEEE Green Book).”

IEEE Std. C37.30, “Standard Requirements for High-Voltage Air Switches.”

IEEE Std. C37.34, “Test Code for High-Voltage Air Switches.”

IEEE Std. C37.35, “Guide for the Application, Installation, and Operation and Maintenance of HighVoltage Air Disconnecting and Load-Interrupter Switches.”

NEMA Std. SG-6, “Power Switching Equipment.”

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”

5.8 SURGE ARRESTERS

5.8.1 General

This section deals with the application of surge arresters for the protection of equipment in substations.

While information is provided for silicon-carbide valve arresters, metal oxide arresters are preferred and

recommended due to their improved protective characteristics. Although the surge arrester is an essential

component in insulation coordination, a complete description of the total concept of insulation

coordination is beyond the scope of this bulletin.

Surge arresters are the basic protective devices against system transient overvoltages that may cause

flashovers and serious damage to equipment. They establish a baseline of transient overvoltage above

which the arrester will operate to protect the equipment. When a transient overvoltage appears at an

arrester location, the arrester conducts internally and discharges the surge energy to ground. Once the

overvoltage is reduced sufficiently, the arrester seals off, or stops conducting, the flow of power follow

current through itself and the circuit is returned to normal. As voltage-sensitive devices, arresters have to

be carefully selected to correlate properly with the system operating voltages.
Bulletin 1724E-300

Page 324

5.8.2 Classification of Arresters

Surge arresters are classified as station, intermediate, and distribution arresters. Classifications are

determined by prescribed test requirements. Primary differences in the use of the classes involve the

voltage levels the arresters will withstand and protect and the current levels the arresters will discharge.

All three classes may be used in substation applications.

Test requirements for gapped silicon-carbide arresters are listed in IEEE Std. C62.1. Table 5-52

indicates the voltage ratings for surge arresters. Table 5-53 indicates the pressure-relief test currents

for the station- and intermediate-class arresters. The application of gapped silicon-carbide surge

arresters is described in ANSI Std. C62.2. The major protective characteristics of the gapped siliconcarbide arresters are summarized in Tables 5-54, 5-55, and 5-56.
Bulletin 1724E-300

Page 325

Table 5-52: Arrester Voltage Ratings in Kilovolts.

Ref. IEEE C62.1-1989, Table 1. Copyright © 1989. IEEE.

All rights reserved.

Secondary

Arresters

Distribution

Arresters

Intermediate

Arresters

Station

Arresters

0.175

0.650

1

3 3 3

9 9 9

10

12 12 12

15 15 15

18

21 21 21

24 24

25

27

30 30 30

36 36

39 39

48 48

60 60

72 72

90 90

96 96

108 108

120 120

144

168

180

192

240

258

276

294

312

372

420

444

468

492

540

576

612

648

684

NOTE: Because of the more stringent requirements for the

protection of rotating machines, the use of arresters (all

classes) rated 4.5, 7.5, 16.5, 18, 19.5, 22.5, 24, 25.5, and 27

kV is recognized for this application.
Bulletin 1724E-300

Page 326

Table 5-53: Pressure-Relief Test Currents for Station and

Intermediate Arresters. Ref. IEEE C62.1-1989, Table 5.

Copyright © 1989. IEEE. All rights reserved.

Symmetrical rms Amperes

High Current Low Current

Station

3–15 kV

ratings * 65000 or 25000 600±200

21–684 kV

ratings ** 40000 or 25000 600±200

Intermediate

3–120 kV

ratings * 16100 600±200

* Test values for arresters with porcelain tops have not

been standardized.

** For applications requiring currents above 40 kA,

ratings of 45, 55, or 60 kA shall be used.

NOTE: It is permissible to determine the prospective

currents by making the bolted fault test with reduced

excitation on the generator (this reduces the duty on the

test equipment). The short-circuit currents and the

open-circuit voltage, ER, with the reduced excitation shall

be measured. The prospective currents of the test

circuit are the measured short-circuit currents multiplied

by ET/ER.
Bulletin 1724E-300

Page 327

Table 5-54: Protective Characteristics of Gapped Silicon-Carbide Station Arresters. Ref. ANSI/IEEE C62.2-1987, Table A1.

Copyright © 1987. IEEE. All rights reserved.

Impulse Sparkover Voltage

Switching

Surge

Discharge Voltage for 8/20-μs Discharge Current Wave

Voltage Front-of-Wave 1.2/50-μs

Sparkover

Voltage

Rating of

Arrester

(kV rms)

Rate of Rise

Test Voltage

(kV/μs)

kV Crest

(Range of

Maxima)

kV Crest

(Range of

Maxima)

kV Crest

(Range of

Maxima)

kV Crest

for 1500A

(Range of

Maxima)

kV Crest

for 3000A

(Range of

Maxima)

kV Crest

for 5000A

(Range of

Maxima)

kV Crest

for 10 000A

(Range of

Maxima)

kV Crest

for 20 000A

(Range of

Maxima)

kV Crest

for 40 000A

(Range of

Maxima)

3 25 10-18 10-14 - 4.7-6 5.3-6.5 6-7 6.7-7.5 7.7-8.3 -9.2

6 50 19-28 16-23 - 9.3-11 10-12 11.9-13 13.4-14.3 15.3-16.3 -18.5

9 75 28.5-38 24-32 - 13.9-17 16-18 17.8-19 20-21.5 22.9-24.3 -28

12 100 36-48 32-41 - 18.5-22 21.3-24 23.5-25.5 26.7-28.5 30.1-32.1 -37

15 125 45-57 40-51 - 23.1-27.5 26.6-30 29.5-32 33.4-36 38.2-40 -46

21 175 63-76 54-68 - 32.3-38.5 37.2-42 41-45 46.8-50 53.4-55.5 -65

24 200 71-86 62-77 - 36.9-44 42.5-48 47-51 53.4-57 61-63.5 -74

30 250 89-103 77-93 - 46.1-55 53.1-60 59-64 66.9-72 76.3-79 -92.5

36 300 107-118 92-108 - 55.3-66 63.7-72 70.5-76 80-85 91.5-94.5 -111

39 325 115-125 100-114 - 60-71.5 69-78 76.5-82.5 56.5-92 99.1-102 -120

48 400 143-148 122-132 - 73.8-88 84.9-96 94-102 106-114 122-126 -148

60 500 170-190 141-165 136-153 95-109 110-120 118-130 132-143 150-158 -185

72 600 204-226 169-190 163-178 114-131 130-144 141-155 159-170 180-189 -222

90 750 254-275 210-235 203-215 142-163 162-180 176-194 199-213 225-237 -277

96 800 270-295 218-245 218-225 151-174 173-192 188-218 212-227 240-253 -296

108 900 304-325 245-270 245-250 170-196 194-216 212-245 238-256 270-284 -333

120 1000 338-360 272-300 272-275 188-218 216-240 235-272 265-285 300-319 -370

144 1200 400-430 326-346 325-326 226-262 260-288 282-311 318-342 360-379 -444

168 1400 460-525 380-404 380-381 263-305 303-336 329-362 371-399 420-442 -517

180 1500 490-565 400-430 400-410 281-327 324-360 353-388 397-427 450-495 -554

192 1600 520-600 427-460 426-435 300-348 346-384 376-414 424-455 480-505 -591

240 2000 620-735 535-577 533-545 374-436 432-480 470-518 530-570 605-630 -739

258 2000 760-790 575-620 573-585 402-438 465-474 505-515 569-575 650-666 -795

276 2000 805-840 615-664 612-630 429-468 496-507 540-570 609-615 690-714 -850

294 2000 875-885 653-675 653-675 458-472 528-532 576-595 653-653 735-758 -906

312 2000 924-935 690-750 693-710 485-530 562-574 611-620 688-693 780-805 874-961

372 2000 1078-1100 870-890 790-830 562-610 655-680 726-738 809-826 932-955 1136-1145

396 2000 1140-1176 925-950 840-885 599-672 697-726 734-785 861-880 990-1015 1109-1226

420 2000 1200-1250 980-1005 890-940 634-713 739-770 819-830 913-930 1050-1070 1176-1294

444 2000 1265-1320 1035-1055 940-990 670-753 781-814 866-875 965-977 1110-1130 1243-1358

468 2000 1326-1390 1090-1110 992-1045 707-794 823-860 913-930 1018-1040 1170-1200 1310-1441

492 2000 1385-1425 1160-1165 1045-1090 742-830 865-925 958-1000 1070-1115 1232-1290 1500-1515

540 2000 1515-1555 1274-1280 1145-1200 814-890 949-990 1052-1070 1173-1195 1350-1390 1646-1663

576 2000 1616-1665 1359-1380 1225-1285 868-950 1012-1060 1122-1150 1251-1285 1440-1480 1755-1780

612 2000 1700-1765 1440-1480 1300-1370 924-1010 1076-1130 1193-1220 1330-1360 1531-1580 1865-1885

648 2000 1790-1865 1525-1570 1380-1445 977-1070 1138-1190 1261-1290 1407-1440 1619-1670 1974-1996

684 2000 1880-1960 1610-1680 1455-1525 1031-1130 1153-1260 1331-1360 1489-1520 1709-1765 2063-2107
Bulletin 1724E-300

Page 328

Table 5-55: Protective Characteristics of Gapped Silicon-Carbide Intermediate Valve Arresters. Ref. ANSI/IEEE C62.2-1987, Table A2.

Copyright © 1987. IEEE. All rights reserved.

Impulse Sparkover Voltage

Discharge Voltage for 8/20-μs Discharge Current Wave

Voltage Front-of-Wave

Rating of

Arrester

(kV rms)

Rate of Rise of

Test Voltage

(kV/μs)

kV Crest

(Range of

Maxima)

1.2/50-μs

kV Crest

(Range of

Maxima)

Switching

Surge

Sparkover

Voltage

kV Crest

(Range of

Maxima)

kV Crest

for 1500A

(Range of

Maxima)

kV Crest

for 3000A

(Range of

Maxima)

kV Crest

for 5000A

(Range of

Maxima)

kV Crest

for 10 000A

(Range of

Maxima)

kV Crest

for 20 000A

(Range of

Maxima)

3 25 11-12 11-12 - 5.2-7.5 6-8 6.6-9 7.5-10 8.7-12

6 50 21-21 19-19 - 10.4-13.5 11.9-14 13.2-15.5 15-17.5 17.4-20

9 75 31-33 27.5-32 - 15.6-21 17.9-23 19.8-25 22.5-28 26.1-31

12 100 38-42 35.5-37 - 20.8-27 23.8-29 26.4-32 30-34 34.8-37.5

15 125 47-51 43.5-46.5 - 25.9-34 29.7-36.5 32.9-39.5 37.5-43 43.5-47.5

21 175 67-73 58-64 - 36.3-47.5 41.6-51 46.1-56 52.5-60 60.9-66

24 200 75-78 66-75 - 41.5-54 47.6-58 52.7-64 60-68 69.6-75

30 250 91-97 81-91 - 51.8-68 59.4-73 65.8-79 75-86 87-95

36 300 108-116 95-103 - 62.2-82 71.3-87 79-95 90-102 104-113

39 325 116-126 102-110 - 67.4-91 77.3-97 85.5-106 97.5-114 113-126

48 400 143-154 121-132 - 83-109 95-116 105-127 120-136 139-150

60 500 166-190 147-155 185-206 104-136 119-145 131-159 150-171 174-189

72 600 201-230 171-191 219-245 124-163 143-174 158-191 180-204 209-225

90 750 250-283 223-233 274-304 155-204 178-218 197-239 225-256 261-282

96 800 268-300 236-250 292-323 166-217 190-232 211-254 240-273 278-300

108 900 283-335 258-265 328-362 187-244 214-261 237-286 270-307 313-338

120 1000 299-370 276-295 351-400 207-272 238-290 263-319 300-338 348-380
Bulletin 1724E-300

Page 329

Table 5-56: Protective Characteristics of Gapped Silicon-Carbide Distribution Arresters. Ref. ANSI/IEEE C62.2-1987, Table A3.

Copyright © 1987. IEEE. All rights reserved.

Impulse Sparkover Voltage

Front of Wave 1.2/50μs

Without

External

Gap

With

External

Gap

Without

External

Gap

With

External

Gap Discharge Voltage for 8/20-μs Discharge Current Wave

Voltage

Rating of

Arrester

(kV rms)

Rate of Rise

of

Test Voltage

(kV/μs)

kV Crest

(Range of

Maxima)

kV Crest

(Range of

Maxima)

kV Crest

(Range of

Maxima)

kV Crest

(Range of

Maxima)

kV Crest

for 1500 A

(Range of

Maxima)

kV Crest

for 3000 A

(Range of

Maxima)

kV Crest

for 5000 A

(Range of

Maxima)

kV Crest

for 10 000 A

(Range of

Maxima)

kV Crest

for 20 000 A

(Range of

Maxima)

3 25 14-25 24-38 12-22 24-37 8-10 8.4-11.5 10-12.4 11.5-13.8 13.5-15.7

6 50 27-35 45-57 23-33 35-55 16-20 17-23 20-24 22.5-26 25-30

9 75 39-48 60-76 34-45 48-65 24-30 25-34 29-36.5 32.5-41 36-52

10 83.3 40-48 62-76 35-49 48-67 25-30 37.5-34 29.5-37 32.5-44 36-52

12 100 49-60 73-96 44-57 59-85 32-40 34-46 29.5-48 43-53 49-61.5

15 125 47-75 80-115 49-65 69-100 40-50 42-55 39-60 54-65.5 60-76

18 150 55-90 96-133 58-76 79-118 48-60 51-66 46-72 65-78 71-91

21 175 63-90 110-139 66-78 -123 56-70 59-75 68-80.5 73-90 82-103

27 225 79-102 - 75-98 - 70-80 76-86 82-94 90-105 99-121

30 250 86-114 - 81-100 - 76-89 84-97 91-105 100-116 111-134
Bulletin 1724E-300

Page 330

Test requirements for metal oxide surge arresters are listed in IEEE Std. C62.11. Table 5-57 indicates

the maximum continuous operating voltage (MCOV) and duty-cycle ratings for surge arresters. The

application of metal oxide surge arresters is described IEEE Std. C62.22. The major protective

characteristics of metal oxide arresters are summarized in Table 5-58.

Table 5-57: Metal Oxide Arrester Ratings in (kV) rms.

Ref. IEEE C62.11-1993, Table 1.

Copyright © 1993. IEEE. All rights reserved.

Duty-Cycle

Voltage MCOV Duty-CycleVoltage MCOV

3 2.55 132 106

6 5.10 144 115

9 7.65 168 131

10 8.40 172 140

12 10.20 180 144

15 12.70 192 152

18 15.30 228 180

21 17.00 240 190

24 19.50 258 209

27 22.00 264 212

30 24.40 276 220

36 29.00 288 230

39 31.50 294 235

45 36.50 312 245

48 39.00 396 318

54 42.00 420 335

60 48.00 444 353

72 57.00 468 372

90 70.00 492 392

96 76.00 540 428

108 84.00 564 448

120 98.00 576 462

588 470

612 485

NOTE: For ratings not shown, consult with the manufacturer.
Bulletin 1724E-300

Page 331

Table 5-58: Metal Oxide Station- and Intermediate-Class Arrester Characteristics. Ref. IEEE C62.22-1991, Table 1.

Copyright © 1987. IEEE. All rights reserved.

Station Class

Steady-State Operation

System Voltage and Arrester Ratings

Protective Levels

Range of Industry Maxima Per Unit—Crest of MCOV

Durability Characteristics

(IEEE Std C62.11-1987 [9])

Maximum

System

Voltage L-L

(kV/rms)

Maximum

System

Voltage L-G

(kV/rms)*

Minimum

MCOV

Rating

(kV/rms)

Duty Cycle

Ratings

(kV/rms)

0.5 μs FOW

Discharge

Voltage (DV)

(NOTE 1)

8/20 μs wave DV

(NOTE 1)

Switching

Surge—DV

(NOTE 2)

High-Current

Withstand Crest

(Amperes)

Transmission

Line

Discharge

(Miles)

Pressure Relief

(A rms)

(Symmetrical)

(NOTE 3)

4.37 2.52 2.55 3- 2.32-2.48 2.10-2.20 1.70-1.85 65 000 150 40 000-65 000

8.73 5.04 5.1 6-9 2.33-2.48 1.97-2.23 1.70-1.85 65 000 150 40 000-65 000

13.1 4.56 7.65 9-12 2.33-2.48 1.79-2.23 1.70-1.85 65 000 150 40 000-65 000

13.9 8.00 7.65 9-15 2.33-2.48 1.97-2.23 1.70-1.85 65 000 150 40 000-65 000

14.5 8.37 8.4 10-15 2.33-2.48 1.97-2.23 1.70-1.85 65 000 150 40 000-65 000

26.2 15.12 15.3 18-27 2.33-2.48 1.97-2.23 1.70-1.85 65 000 150 40 000-65 000

36.2 20.92 22 27-36 2.43-2.48 1.97-2.23 1.70-1.85 65 000 150 40 000-65 000

48.3 27.89 29 36-48 2.43-2.48 1.97-2.23 1.70-1.85 65 000 150 40 000-65 000

72.5 41.86 42 54-72 2.19-2.40 1.97-2.18 1.64-1.84 65 000 150 40 000-65 000

121 69.86 70 90-120 2.19-2.40 1.97-2.18 1.64-1.84 65 000 150 40 000-65 000

145 83.72 84 104-144 2.19-2.39 1.97-2.17 1.64-1.84 65 000 150 40 000-65 000

169 97.57 98 120-172 2.19-2.39 1.97-2.17 1.64-1.84 65 000 175 40 000-65 000

242 139.72 140 172-240 2.19-2.36 1.97-2.15 1.64-1.84 65 000 175 40 000-65 000

362 209.00 209 258-312 2.19-2.36 1.97-2.15 1.71-1.85 65 000 200 40 000-65 000

550 317.54 318 396-564 2.01-2.25 2.01-2.25 1.71-1.85 65 000 200 40 000-65 000

800 461.88 462 576-612 2.01-2.25 2.01-2.25 1.71-1.85 65 000 200 40 000-65 000

Intermediate Class

4.37-169 2.52-97.67 2.8-98 3-144 2.38-2.85 2.28-2.55 1.80-2.10 65 000 100 16100 (NOTE 3)

* Voltage range A, ANSI C84.1-1989 [1].

NOTE 1: Equivalent FOW producing a voltage wave cresting in 0.5 μs. Protective level is maximum DV for a 10 kA impulse current wave on

arrester duty cycle rating through 312 kV, 15 kA for duty cycle ratings 396-564 kV, and 20 kA for duty cycle ratings 576-612 kV, per

IEEE Std. C62.11-1987 [9].

NOTE 2: Switching surge characteristics based on maximum switching surge classifying current (based on an impulse current wave with a time

to actual crest of 45 μs to 60 μs) of 500 A on arrester duty cycle ratings 3-108 kV, 1000 A on duty cycle ratings 120-240 kV, and

2000 A on duty cycle ratings above 240 kV, per IEEE Std. C62.11-1987 [9].

NOTE 3: Test values for arresters with porcelain tops have not been standardized.
Bulletin 1724E-300

Page 332

Relative protective capabilities and initial costs of surge arresters, in descending order, are station-class,

intermediate-class, and finally distribution-class arresters. The appropriate arrester has to be determined

from an analysis of the protective characteristics required, the importance of the equipment protected, the

level of reliability desired, and the overall cost of protection.

Refer to RUS IP 202-1 for a listing of surge arresters that may be used in the cooperative’s substations.

5.8.2.1 Station Class Arresters: Station-class arresters are more ruggedly constructed than those in

either the intermediate or distribution class. They have greater surge current discharge ability and lower

IR voltage drop, thus affording better protection. In the event of arrester failure, their ability to vent

safely during high system short-circuit currents is better than the other classes of arresters.

Station-class arresters are recommended for all substations of large capacity (10,000 kVA and above) and

on smaller substations that are of prime importance. They should be applied on transmission circuits

longer than approximately 100 miles or where shunt capacitor banks are installed.

Station-class arresters are also desirable on substations using reduced insulation (BIL) or those located in

high lightning exposure areas. They should be used where the system short-circuit current exceeds the

venting capability of intermediate-class arresters. They are the only class of arrester available for use on

systems above 150 kV.

5.8.2.2 Intermediate Class Arresters: Intermediate-class arresters may be used in substations rated

below 10,000 kVA at a cost saving when compared to station-class arresters. Their electrical protective

characteristics (sparkover and IR) are higher than station-class arresters, but are usually adequate for

small substations. In the event of arrester failure, intermediate-class arresters can safely vent with shortcircuit current of 16,000 amperes or less. Intermediate-class arresters are available in ratings 3 kV

through 120 kV.

5.8.2.3 Distribution-Class Arresters: Distribution-class arresters may be used on the low-voltage

side of distribution substations. Install them on the load side of feeder overcurrent protective devices

(reclosers or breakers). They are frequently applied connected to the low-voltage bushings of small

distribution substation transformers. Their protective characteristics are not as good as either

intermediate- or station-class arresters. If distribution-class arresters are used in substations, use only the

direct-connected type with ground lead disconnector (isolator).

5.8.3 Ratings (Standard Definitions)

5.8.3.1 Voltage Rating–Duty Cycle (kV rms): The designated maximum permissible operating

voltage between its terminals at which an arrester is designed to perform its duty cycle. It is the voltage

rating specified on the nameplate. This rating is applicable specifically to the silicon-carbide valve

arrester and is also typically listed with the MCOV rating for the metal oxide arrester.

5.8.3.2 Power-Frequency Sparkover Voltage: The root-mean-square value of the lowest power

frequency sinusoidal voltage that will cause sparkover when applied across the terminals of an arrester.

This rating is applicable to the silicon-carbide valve arrester.

5.8.3.3 Impulse Sparkover Voltage: The highest value of voltage attained by an impulse of a

designated wave shape and polarity applied across the terminals of an arrester prior to the flow of

discharge current. This rating is applicable to the silicon-carbide valve arrester.
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Standard wave shape is a 1.2 x 50 μs wave, i.e., a wave that rises to crest in 1.2 μs and decays to one-half

crest value in 50 μs.

5.8.3.4 Maximum Continuous Operating Voltage (MCOV): The maximum continuous operating

voltage is the maximum rms power frequency operating voltage that may be applied continuously to the

terminals of the arrester. When applying metal oxide surge arresters, the minimum value of this voltage

is usually the maximum system line-to-ground voltage.

5.8.3.5 Discharge Current: The discharge current is the current that flows through an arrester as a

result of a surge.

5.8.3.6 Discharge Voltage: The voltage that appears across the terminals of an arrester during the

passage of discharge current. Maximum values are usually available from the manufacturer for currents

of 1.5, 3, 5, 10, 20, and 40 kA with a wave shape of 8 x 20 μs. The discharge voltage resulting from a

standard 8 x 20 μs current wave shape approximates the standard 1.2 x 50 μs voltage wave shape

reasonably well between the current magnitudes of 5 kA and 20 kA.

The 8 x 20 μs standard current wave shape is one that rises to crest in 8 μs and decays to one-half crest

value in 20 μs. The 1.2 x 50 μs voltage wave shape is one that rises to crest in 1.2 μs and decays to onehalf crest value in 50 μs.

5.8.3.7 Discharge-Voltage Current Characteristic: The discharge-voltage current characteristic is

the variation of the crest values of discharge voltage with respect to discharge current.

5.8.4 System Voltage

System voltages carry two designations: nominal voltage and maximum system voltage.

5.8.4.1 Nominal Voltage: Nominal voltage is the approximate phase-to-phase voltage

distinguishing one system from another. The nominal voltage is the voltage by which the system may be

designated and is near the voltage level at which the system normally operates. The nominal voltage is

usually approximately 5 to 10 percent below the maximum system voltage.

5.8.4.2 Maximum System Voltage: Maximum system voltage is the highest rms phase-to-phase

operating voltage that occurs, the highest phase-to-phase voltage for which equipment is designed for

satisfactory continuous operation without derating of any kind. It is the starting basis on which surge

arresters are applied.

Maximum system voltages are generally those prescribed in ANSI Std. C84.1, “Voltage Ratings for

Electric Power Systems and Equipment (60 Hz).” On systems rated 345 kV and below, it is expected that

the maximum system voltage may be 5 to 10 percent higher than nominal voltage.

5.8.5 Grounded vs. Ungrounded Systems

Systems have been historically referred to as effectively grounded when coefficient* of grounding (COG)

does not exceed 80 percent, or noneffectively grounded or ungrounded when coefficient* of grounding

exceeds 80 percent.
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A COG value not exceeding 80 percent is obtained approximately when, for all system conditions, the

ratio of zero sequence reactance to positive sequence reactance (X0/X1) is positive and less than three,

and the ratio of zero-sequence resistance to positive-sequence reactance (R0/X1) is positive and less than

one.

On certain distribution systems of the four-wire type where transformer neutrals and neutral conductors

are directly grounded at frequent points along the circuit, the positive sequence resistance (R) may be

significant due to small conductors and should be considered.

Neglecting the resistance component may result in higher rated arresters than normally required. In these

cases, use ratios R0/Z and X0/Z1. The COG for such systems may be as low as 67 percent. On many

high-voltage transmission systems, the COG may be as low as 70 percent. Recognize the possibility of

increases in the COG due to system switching or changes.

ANSI/IEEE Std. C62.92, “IEEE Guide for the Application of Neutral Grounding in Electrical Utility

Systems Part I—Introduction,” provides a more detailed and thorough discussion of the effects of

grounding and the calculation of the COG.

5.8.6 Application Guide for Silicon-Carbide Valve Arresters

5.8.6.1 General: The voltage rating assigned to a surge arrester should exceed the maximum 60 Hz

voltage across its terminals during normal or fault conditions. In general, the surge arrester voltage rating

should be at least 25 percent higher than the phase-to-ground voltage when the system is operating at

maximum phase-to-phase voltage.

On an isolated neutral system, which may be a delta system or an ungrounded-wye system, this rating

should be approximately 105 percent of, and never less than, the maximum rating of the system. Such an

arrester is called a “full-rated” or 100 percent arrester. On effectively grounded systems, the arrester

maximum rating can generally be 80 percent or less of the maximum system voltage. In special cases,

arresters as low as 75 percent or even 70 percent of maximum system voltage rating may be applied,

depending on the coefficient of grounding of the system.

5.8.6.2 Maximum Phase-to-Ground Voltage: The first step recommended in selecting a lightning

arrester is to determine the maximum phase-to-ground power-frequency overvoltage at the arrester

location. This maximum overvoltage may occur as a result of a fault condition, sudden loss of load, or

resonance. Overvoltages experienced as a result of loss of load or resonance are determined by system

operating experience or by computer studies. Overvoltages that result from these two conditions are not

expected to be significant for most applications at 230 kV and below.

At 345 kV, the switching surge protection level may be more significant than the lightning impulse

protection level. At the higher voltage level, capacitance of the line will be more significant. On any

long line, the voltage of the line will increase over distance. With the line energized during switching

operations from one end of the line only, the remote end will experience a voltage increase. In addition, if

*The coefficient of grounding (COG) is the ratio of E LG /E LL. The COG is expressed as a

percentage of the highest root-mean-square line-to-ground power-frequency voltage, E LG, on a

sound phase, at a selected location, during a fault to ground affecting one or more phases to the

line-to-line power-frequency voltage, E LL, that would be obtained, at the selected location, with

the fault removed.
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the energizing source is a relatively weak source, the line could experience transient oscillations resulting

in additional voltage increase. The additional line capacitance will tend to make the line more susceptible

to transients than the lower voltage lines. Switching of a 345 kV line terminated with a transformer could

result in transients if resonance conditions are present. These conditions could result in the overstressing

of surge arresters due to multiple restrikes through the arrester. Transient network analysis (TNA) or

electromagnetic transient program analysis (EMTP) may be necessary to determine the size of the arrester

to be applied. The study could also determine other means to control transient overvoltage conditions

such as the application of reactors, pre-insertion resistors, or specific operating practices to be followed

during switching.

Determination of the overvoltage due to a fault condition is necessary for any power system where less

than full line-to-line rated arresters are to be considered. The maximum line-to-line voltage at the point of

arrester application multiplied by the COG based on a fault at the arrester location will often result in the

maximum voltage to be applied. This may vary, however, depending on the system configuration. The

application of neutral impedance elements may shift the location of the maximum voltage on a line with

the shift of the transformer neutral during a phase-to-ground fault.

The COG may be estimated using the graphs of Figure 5-33 or calculated from system values. When

calculating the COG for use with machines, the subtransient reactance of the machine is recommended for

use. With EHV systems, consider the effects of shunt reactors, capacitance, series capacitance, or

reactors when applicable.

5.8.6.3 Protective Margins: The lower the arrester rating on a given system, the greater the

protective margin for the insulation of the protected equipment. When system studies or calculations

show that protective margins would be more than adequate, the BIL of major equipment may be reduced

for substantial savings. Generally, the accepted practice is to provide a minimum margin of 20 percent

between transformer BIL and surge arrester maximum IR, and 15 percent in the case of switching surges.

The switching surge withstand strength of transformer insulation is usually specified at 83 percent of

impulse BIL. Greater margins may be required where a condition of insulation degradation may be

present.

Examine the protective margins over the full volt–time characteristics of the insulation that is to be

protected and the volt–time characteristics of the arrester. Also maintain sufficient margin regardless of

the relative physical location of the arrester and protected equipment in the substation. Locate the arrester

as close to the major equipment as possible, and the arrester ground resistance should be low. Connect

surge arrester grounds reliably to the substation ground grid and with the frames of all equipment being

protected.

5.8.6.4 Thermal Capacity: The arrester thermal capacity or ability to pass repeated or long-duration

surge currents (such as switching surges) without an internal temperature rise, which could fail the

arrester, has to be checked. This is especially true in all cases where there are long lines or shunt

capacitor banks with high stored energy. Available switching surge energy increases as the square of the

system voltage and directly with the length of lines. Thus, on 138 kV lines of equal length to 69 kV lines,

the surge arresters have to have at least four times the discharge capacity.

5.8.6.5 Direct Stroke Shielding: Surge arresters are applied primarily based on their effectiveness

in limiting overvoltages in the form of traveling waves entering the substation over connecting lines.

High-energy lightning strokes hitting a substation bus at or near the arrester could easily destroy the

arrester while it is attempting to pass the surge current to ground. Even if the arrester is not destroyed, the
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Figure 5-33: Coefficient of Grounding for Various System Conditions. Ref. IEEE C62.2, Figure 2.

Copyright © 1987. IEEE. All rights reserved.
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protective margins provided may become nonexistent as a result of the effect of the steep fronts and high

IR voltage produced by the arrester.

Therefore, a basic principle of surge arrester application is the provision of overhead ground wires and/or

grounded conducting masts to shield substation electrical equipment against direct lightning strokes.

Effective shielding also permits greater separation of a surge arrester from the equipment being protected

since the overvoltage impulses are less steep and are usually of lower magnitude.

5.8.6.6 Multiple Lines: It is well recognized that the severity of a lightning impulse arriving at a

substation is reduced by the effect of multiple lines. Traveling waves coming into a substation will divert

part of the energy in the wave over all line connections. It is difficult, however, to take full advantage of

this since one cannot be sure the lines will be connected when needed. In addition, in substations with

long buses, etc., the distances sometimes prevent effective use of this principle.

5.8.6.7 Standards and Guides: There are two principal national standards or guides pertaining to

silicon-carbide valve surge arresters: IEEE Stds. C62.1 and C62.2.

5.8.6.7.1 IEEE C62.1, “IEEE Standard for Gapped Silicon-Carbide Surge Arresters for AlternatingCurrent Power Circuits.” This standard contains much basic information on arresters such as definitions,

service conditions, classification and voltage ratings, performance characteristics and tests, test

procedures, design tests, conformance tests, and construction. Some pertinent sections are as follows:

a. Section 4, Service Conditions.

b. Standard arresters are designed for ambient temperatures not exceeding 40°C (104°F) and

altitudes not exceeding 1800 meters (6000 feet).

c. Section 5.1, Table 1 (see Table 5-52), Voltage in Kilovolts, lists the standard voltage ratings

available in distribution-, intermediate-, and station-class arresters.

d. Section 7.2, Table 2, Test Requirements for Arrester Classification, summarizes the sections

dealing with test requirements for the different arrester classifications: distribution,

intermediate, and station.

e. Section 8.1, Table 3, Insulation Withstand Test Voltages, lists the various insulation

requirements of all ratings of the different arrester classifications, with the internal parts

removed.

f. Section 8.9, Table 5 (see Table 5-53), Pressure-Relief Test Currents for Station and

Intermediate Arresters, lists the symmetrical rms amperes short-circuit capability of various

ratings of station and intermediate arresters.

5.8.6.7.2 A guide for application of valve-type lightning arresters for alternating-current systems can

be found in ANSI/IEEE Std. C62.2. This standard is an excellent guide on application of arresters. It

contains information on general procedures; systematic procedures for protection of transformers and

substation equipment; and protection of other equipment such as booster transformers, reactors, current

transformers, etc. Of particular interest is the Typical Voltage–Time Curve for Coordination of Arrester

Protective Levels with Insulation Withstand Strength (see Figure 5-34). This curve illustrates the

protection provided by an arrester to transformer insulation.

Appendix A to IEEE Std. C62.2, Protective Characteristics of Surge Arresters, contains data on protective

characteristics of available arresters compiled from domestic manufacturers. This is very useful for

general studies, but it should be kept in mind that the voltage values given are the maximums of the
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Figure 5-34: Typical Voltage–Time Curve for Coordination of Arrester Protective Levels

with Insulation Withstand Strength for Liquid-Filled Transformers.

Ref. IEEE Std. C62.2-1987, Figure 3. Copyright © 1987. IEEE. All rights reserved.
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published protective characteristics. Consult specific manufacturer’s information for more accurate

insulation coordination.

Appendix B to IEEE Std. C62.2, Surge Arrester Applications for EHV Systems, provides important

considerations concerning switching surges. It is generally necessary to consider switching surge

protective levels only for application on systems above 69 kV. In most cases, insulation coordination

levels will not be affected by switching surges except at levels at 345 kV or above.

5.8.6.8 Guide Steps for Application of Valve-Type Surge Arresters for AC Systems (see IEEE

Std. 62.2): An example of surge arrester selection will be worked out along with each guide step to

illustrate the procedure. The example is arrester selection for a 230 kV substation coordinated with the

transformer BIL. The 230 kV substation is supplied by one 230 kV line. Both the substation and the line

are effectively shielded.

5.8.6.8.1 Determine the maximum phase-to-ground temporary overvoltage at the arrester location. In

most cases, this will depend on the coefficient of system grounding.

Example: At the surge arrester location, system parameters are known to be:

Rl = R2 = 0.1∗X1, R0/X1 = 0.8, and X0/X1 = 2.5

From curve (B) of Figure 5-33, the coefficient of grounding is 75 percent. Maximum system voltage is

230 kV x 1.05 or 242 kV. Maximum phase-to-ground overvoltage during a ground fault is 242 kV x 0.75

or 181 kV. No other conditions including switching configurations are considered to result in temporary

overvoltages that will exceed this voltage level.

5.8.6.8.2 Estimate the waveshape and magnitude of arrester discharge current. The magnitude is

determined largely by the effectiveness of the shielding against direct lightning strokes.

Example: The standard arrester discharge current curve (a 8 x 20 μs wave) represents the most severe

current waveshape to be expected at a substation that is effectively shielded. Surge arrester discharge

voltage characteristics (IR drop) are based on this standard curve. A conservative value of maximum

current with effective shielding is 10 kA. The current could reach as high as 20 kA or higher if the

substation is not effectively shielded.

5.8.6.8.3 Tentatively select arrester class and voltage rating.

Example: A station-class surge arrester has to be selected since this is the only type available at this

voltage level. The substation size and importance may indicate a station-class arrester regardless of

system voltage. Arrester voltage rating has to be at least 181 kV, as determined in Step 1. Another rule of

thumb recommends that the arrester voltage rating be not less than 125 percent of the voltage to ground

when the system is operating at maximum system voltage:

1.25 x 1.05 x 230 kV/ 3 = 174 kV

The next standard arrester rating above 174 kV and 181 kV is 192 kV. Therefore, 192 kV is selected as

the tentative arrester rating.
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5.8.6.8.4 Determine the impulse and switching surge protective levels of the tentatively selected

arrester. The necessary information may be obtained from the arrester manufacturer or approximately

from Appendix A of IEEE Std. 62.1 (see Table 5-53).

Example: Typical surge arrester characteristics are obtained from the arrester manufacturer’s published

data. These characteristics include maximum sparkover (S.O.) on front of wave; maximum S.O. on full

wave of 1.2 x 50 μs; maximum S.O. on switching surge (S.S.), maximum discharge voltage for 5, 10, and

20 kA of discharge current; and minimum S.O. on 60 Hz voltage. Typical characteristics are shown

plotted on Figure 5-34.

Calculate the maximum theoretical surge voltages that could appear at the insulation to be protected.

These will depend on many factors, such as effectiveness of shielding, number of lines normally

connected, and relative location of an arrester to protected equipment.

Example: For most applications, it is sufficient to rely on the recommended minimum margins between

protection levels provided by the surge arrester and the BIL of the protected equipment. See Section

5.8.6.8.5.

Calculate the minimum permissible withstand strength of the insulation to be protected. The necessary

information may be obtained from manufacturers of the equipment. Approximate information may be

obtained from applicable standards on the type of equipment.

Example: The impulse withstand strength of equipment is defined by its full-wave impulse test voltage

using a standard 1.2 x 50 μs wave. The strength is greater for shorter duration voltage peaks. See Figure 5-35 for curves showing withstand strength of a power transformer over the range of 0 to 5,000 μs.

5.8.6.8.5 Evaluation of Insulation Coordination: (Front of Wave 20 percent; maximum discharge 20

percent; maximum switching surge 15 percent.)

Example: See Figure 5-35 for the coordination of surge arrester protective levels with 230 kV

transformer BIL. Possible BILs of 900, 825, 750, and 650 kV are shown. All BILs are adequately

protected from impulses or switching surges. However, other factors have to be considered such as 60 Hz

withstand, both internal and external; future deterioration of the insulation; surge arrester location with

respect to the transformer; etc. A BIL of 750 kV would appear to be a proper choice based on the

conditions assumed. The surge arrester voltage rating of 192 kV is a proper selection unless there are

unusual system conditions that could subject the arrester to voltages above its rating.

5.8.6.8.6 Insulation Coordination Calculation Iterations: When coordination cannot be achieved, the

solution may be to select a different arrester, improve arrester location relative to protected equipment,

increase the insulation level of protected equipment, improve shielding, or install additional arresters.

5.8.6.8.7 Transformer Arrester Rating Coordination: When the transformer high-voltage side arrester

has been chosen, compare the rating on a per unit basis to the arrester rating for the low-voltage winding.

The arrester applied to the low voltage of a transformer should have a rating slightly higher than the rating

of the high-voltage winding. An impulse that hits the high-voltage winding will also be transformed to

the low-voltage winding via the transformer turns ratio with the corresponding voltage and current. If the

energy is discharged through the low-voltage winding arresters, the current discharged through the lowvoltage winding arresters will be the transformer turns ratio times the high-voltage arrester discharge
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Figure 5-35: Typical Volt–Time Curves for Coordination of Metal Oxide Surge Arrester Protective Levels with Insulation Withstand Strength
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current. Make sure that energy will discharge through the high-voltage winding arresters before it will

discharge through the low-voltage winding arresters.

5.8.7 Application Guide for Metal Oxide Surge Arresters

Metal oxide arresters were developed after the application of silicon-carbide valve arresters to electric

power systems. The primary component of the arrester that differentiates metal oxide arresters from the

previous arresters is the zinc oxide valve that has significantly greater non-linear volt – current

characteristics as compared to previous devices. The zinc oxide valve operates more closely to that of a

zener diode that is applied in the electronic industry. The valve is capable of being applied without any

gaps in the design, eliminating the sparkover characteristic of previous arresters (see Figure 5-36) as it

eases into conduction. The zinc oxide valve typically provides lower discharge voltages than available

with previous designs.

Figure 5-36: Gapless Metal Oxide Surge Arrester. Ref. IEEE Std. C62.22-1991, Figure 1.

Copyright © 1991. IEEE. All rights reserved.

5.8.7.1 Types of Metal Oxide Surge Arresters: In addition to the silicon-carbide station,

intermediate, and distribution classes of arresters, development of the metal oxide arrester has produced

three basic categories of arresters. These categories are known as the gapless, shunt-gapped, and seriesgapped metal oxide arresters.

5.8.7.1.1 Gapless Metal Oxide Surge Arresters: Gapless arresters consist of a stack or multiple stacks

of metal oxide disks (see Figure 5-36). Above the MCOV rating, the arrester exhibits a very non-linear

behavior. This arrester is applied directly to the line terminal and ground with only its inherent

impedance limiting the amount of leakage current through the arrester.

5.8.7.1.2 Shunt-Gapped Metal Oxide Surge Arresters: Shunt-gapped metal oxide arresters consist of

a stack of metal oxide disks that are bridged by shunt gaps (See Figure 5-37). When the disks start to

conduct current upon the arrival of a surge, the discharge voltage will increase to the point where the gaps

will spark over and short the associated disks. The sparkover of the gaps, typically at several hundred

amps (range B to C), has the effect of reducing the discharge voltage of the arrester (range D to E). A

decrease in the amount of discharge current will eventually extinguish the gap current, causing the voltage

to increase to its initial curve, A-B-C.
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Figure 5-37: Shunt-Gapped Metal-Oxide Surge Arrester.

Ref. IEEE Std. C62.22-1991, Figure 2.

Copyright © 1991. IEEE. All rights reserved.

5.8.7.1.3 Series-Gapped Metal Oxide Surge Arresters: The series-gapped metal oxide arresters use

fewer disks in series with a series gap impedance network (see Figure 5-38). As the arrester starts to

conduct, the voltage is divided between the disks and the gap network. When the voltage across the

gapped impedance network increases to the point the gap sparks over, the voltage is reduced across the

total arrester to be that which is across the metal oxide disks.

Figure 5-38: Series-Gapped Metal Oxide Surge Arrester.

Ref. IEEE Std. C62.22-1991, Figure 3.

Copyright © 1991. IEEE. All rights reserved.

The application of metal oxide surge arresters is similar to the application of silicon-carbide arresters in

terms of the system information that is required. The system parameters of the maximum system

operating voltage and temporary overvoltages are of primary importance in the application of this type of

arrester. The discharge current levels are also important to the application of this arrester.

5.8.7.2 Operating Conditions: Usual operating conditions for surge arresters include continuous air

temperature ratings between –40°C and +40°C with maximum air temperatures of +60°C at elevations

less than 1800 meters (6000 ft). Unusual operating considerations could include operation in enclosed
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areas or in areas contaminated by gas fumes or external air contamination. Confirm special operating

conditions with the manufacturer before the applications are made.

5.8.7.3 Maximum Phase-to-Ground Voltage

5.8.7.3.1 Maximum Continuous Operating Voltage: Metal oxide arresters are applied primarily based

on the MCOV. Metal oxide arresters have been assigned dual voltage ratings based on the conventional

duty-cycle rating and the newer MCOV rating (see Table 5-57). Of primary importance is the

requirement that the MCOV of the applied arrester be above the maximum continuous operating voltage

of the electric system. For a solidly grounded system with the maximum operating allowance of 5

percent, the minimum MCOV is calculated using Equation 5-7:

Equation 5-7

MCOV(MIN) = ELL * k / 3

Where:

k = Percentage of operating voltage allowance over the nominal operating voltage

For a 34.5 kV nominal voltage solidly grounded system with a 5 percent maximum operating voltage

allowance, the MCOV is calculated as follows:

34.5 kV ∗ 1.05 / 3 = 21 kV

According to Table 5-57, the nearest MCOV rating above this value is 22 kV. This would be the

minimum rating of the arrester to receive consideration.

The application of arresters on ungrounded or impedance-grounded systems is normally applied on the

basis of their associated duty-cycle rating. Using the arresters on the basis of 100 percent voltage

application, the minimum duty-cycle rating for the arresters on an ungrounded system will be the

maximum anticipated operating line-to-line voltage. For a 34.5 kV nominal voltage impedance-grounded

or ungrounded system with a 5 percent maximum operating voltage allowance, the duty-cycle rating is

calculated as follows:

Rating = ELL * k

Where:

k = Percentage of operating voltage allowance over the nominal operating voltage

For a 34.5 kV system,

34.5 kV ∗ 1.05 = 36.2 kV

According to Table 5-57, the next highest duty-cycle voltage rating for the arrester is 39 kV. The

corresponding MCOV for this arrester is 31.5 kV. With this MCOV rating, the arrester will move into

conduction should one of the phases be grounded or be faulted. It then becomes a judgment of the

engineer to assess the amount of time the arrester will be required to conduct under these conditions.

Applying a metal oxide arrester under these conditions will make use of the inherent improved temporary

overvoltage capabilities of the devices. Follow the manufacturer’s recommendations regarding the extent

of overvoltage capabilities for a particular arrester when applying arresters on this basis.
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5.8.7.3.2 Maximum Phase-to-Ground Temporary Overvoltage (TOV) at the Arrester Location: In

addition to the MCOV, any temporary operating voltages above the MCOV have to be considered for

magnitude and duration. These conditions may arise due to conditions that include line-to-ground fault

conditions, loss of neutral on a normally grounded system, sudden load rejection, oscillations due to

system resonance, switching surges, switching conditions, etc.

Evaluate each of the conditions resulting in temporary overvoltage in terms of the effect it has on the

system. The magnitude and duration of the overvoltage will assist in determining the proper application

of the arresters. Metal oxide arresters have a significantly improved ability to operate during temporary

overvoltages. Manufacturers typically publish curves to indicate the magnitudes and durations of

overvoltages under which the arresters will successfully operate (see Figure 5-39). Apply the arresters

within the limitations the manufacturer recommends for acceptable overvoltage within the manufacturer’s

specified time limits.

Figure 5-39: Typical 60-Hz Temporary Overvoltage Capability for Metal Oxide Arresters

Temporary overvoltages are most often associated with the overvoltages experienced by the unfaulted

phases during a phase-to-ground fault. These overvoltages are determined in the same way as for siliconcarbide arresters. Other overvoltage conditions on higher voltage lines may require transient network

analysis or similar studies to determine the actual parameters that are required.

5.8.7.4 Arrester Discharge Currents

5.8.7.4.1 Lightning Impulse Discharge Currents: The magnitude of discharge current is largely
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determined by the effectiveness of the shielding against direct lightning strokes. Discharge currents of

5 kA to 20 kA are commonly used to calculate the maximum discharge voltage. This is covered in

Section 5.8.6.8.4 for the silicon-carbide arresters. The same procedures are used here.

5.8.7.4.2 Switching Surge Impulse Currents: Switching surges are seldom a consideration below 345

kV. Accurate determination of surge withstand capabilities will require a transient network analysis or

electromagnetic transient study to be performed. These studies can simulate the transmission system

elements, including the arresters, determine the surge levels that are expected, and size the surge arresters

based on the energy absorption characteristics of the arresters. Approximations of the surge currents can

be made using Equation 5-8:

Equation 5-8

Where:

IA = Surge current (amps)

Es = Surge voltage (volts)

EA = Discharge voltage (volts)

Z = Line surge impedance (ohms)

5.8.7.5 Arrester Discharge Energy: Arrester discharge energy is estimated using Equation 5-9:

Equation 5-9

J = 2 L EA IA / c (kilojoules)

Where:

L = Distance of the transmission line

c = Speed of light at 190 miles per ms or 300 km/ms

Values of the surge current or the energy may be compared to the manufacturer’s data regarding the surge

discharge capability of the arresters.

5.8.7.6 Insulation Coordination: BILs, BSLs, and CWW levels for equipment are obtained from

the equipment standards. Procedures for establishing the coordination are previously given for siliconcarbide arresters.

Typical characteristics collected include the front of wave value at 0.5 μs, the maximum switching surge

protective level, and maximum discharge voltages at 5 kA, 10 kA, and 20 kA. Since the metal oxide

arresters have no sparkover, the front-of-wave value is used in place of the sparkover value.

Acceptable protective margins are considered to be similar to the silicon-carbide protective levels.

Generally accepted practice is to provide a 20 percent margin between the transformer front of wave

(TFOW) strength and the arrester front of wave rating based on the arrester front of wave rating (AFOW),

a 20 percent margin between the BIL withstand rating (BIL) and the arrester lightning protective level

(LPL), and a 15 percent margin between the transformer switching surge withstand (BSL) and the arrester

surge protective level (SPL). The switching surge withstand strength of the transformer insulation is

usually specified at 83 percent of impulse BIL. These ratings are summarized as follows:

Z

E E

I

S A

A

−

=
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Ratio F = TFOW / AFOW ≥ 1.20

Ratio L = BIL / LPL ≥ 1.20

Ratio S = BSL / SPL ≥ 1.15

5.8.7.7 Direct Stroke Shielding: This topic is covered under the application for silicon-carbide

arresters.

5.8.7.8 Multiple Lines: This topic is covered under the application for silicon-carbide arresters.

5.8.7.9 Standards and Guides: There are two principal national standards or guides pertaining to

metal oxide valve surge arresters: IEEE C62.11 and IEEE 62.22.

5.8.7.9.1 IEEE C62.11, “IEEE Standard for Metal-Oxide Surge Arresters for Alternating Current

Power Circuits.” This standard contains basic information on arresters such as definitions, service

conditions, classification and voltage ratings, performance characteristics and tests, test procedures,

design tests, conformance tests, and construction. Some pertinent sections are as follows:

a. Section 4, Service Conditions.

b. Standard arresters are designed for ambient temperatures not exceeding 40°C (104°F) and

altitudes not exceeding 1800 meters (6000 feet).

c. Section 5, Table I (Table 5-57), Voltage in Kilovolts, lists the standard voltage duty ratings

and the corresponding MCOV available for metal oxide arresters.

d. Section 8, Design Tests, indicates the tests that devices have to adhere to so as to comply with

the standard. The differences in the different arrester classifications of distribution,

intermediate, and station class are listed in the various subsections as applicable. The table in

Appendix B of IEEE Std. C62.11, Surge Arrester Classification Prescribed Test Requirements,

summarizes the test values required for the various tests.

e. Section 8.1.1, Table 2a, Insulation Withstand Test Voltages, lists the various insulation

requirements of all ratings of the different arrester classifications.

f. Section 8.3.1, Table 3, Lightning Impulse Classifying Current, lists the impulse value crest

amperes for the various ratings of station, intermediate, and distribution arresters.

g. Section 8.3.2, discharge voltage–time characteristics, lists the surge value crest amperes for the

various ratings of station, intermediate, and distribution arresters.

5.8.7.9.2 IEEE Std. C62.22, “Guide for the Application of Metal-Oxide Surge Arresters for

Alternating-Current Systems.” This standard is an excellent guide to the basic application of metal oxide

arresters in electric substations. It contains information on general procedures, systematic procedures for

protection of transformers and substation equipment, and protection of other equipment such as dry-type

insulation, shunt capacitor banks, underground cables, gas-insulated substations, and rotating machines.

Of particular interest is the Typical Voltage–Time Curve for Coordination of Arrester Protective Levels

with Insulation Withstand Strength for Liquid-Filled Transformers (see Figure 5-40). This curve

illustrates the protection to transformer insulation provided by an arrester.

Appendix A to IEEE Std. C62.22, Lightning Flashes, Lightning Stroke Currents, Traveling Waves, and

Station Shielding, provides a discussion of the characteristics of lightning strokes, densities, current

values, and characteristics. The use of shielding in substations is discussed with respect to prevention of

direct strokes from hitting substation equipment.
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Figure 5-40: Typical Volt–Time Curve for Coordination of Arrester Protective Levels with Insulation Withstand Strength for Liquid-Filled

Transformers. Ref. IEEE Std. C62.22-1991, Figure 8. Copyright © 1991. IEEE. All rights reserved.
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Appendix B to IEEE Std. C62.22, COG for Various Conditions, contains additional information regarding

coefficients of grounding.

Appendix C, Calculations of Surge Arrester Separation Distances, provides additional discussion and

calculation procedures for determining the degree of protection when the surge arrester is separated from

the equipment that is being protected.

5.8.7.10 Guide for the Application of Metal Oxide Surge Arresters for Alternating-Current

Systems (see IEEE Std. 62.22 for details). An example of surge arrester selection will be worked out

along with each guide step to illustrate the procedure. The example is arrester selection for a 230 kV

substation coordinated with the transformer BIL. The 230 kV substation is supplied by one 230 kV line.

Both the substation and the line are effectively shielded. This is the same example used with the siliconcarbide arresters.

5.8.7.10.1 Conditions for Application: The conditions are as indicated in Section 5.8.6.8 and as

follows:

ELL (MAX) = 242 kV ELG(MAX) = 140 kV

Coefficient of grounding (COG): R1 = R2 = 0.1 ∗X1, R0/X1 = 0.8, X0/X1 = 2.5

COG = 75

ELG(MAX TOV) = 181 kV for less than 1 sec during fault conditions (242 ∗ 0.75 = 181)

Possible transformer BILs to investigate (kV): 900, 825, 750, 650

Impulse currents to consider (kA): 5, 10, 20

Switching surge: Not applicable for transformer

5.8.7.10.2 Arrester Selection: Minimum MCOV rating for the application is 140 kV equal to the

ELG(MAX). Table 5-57 indicates this rating is a standard rating and, as such, is chosen as the initial MCOV

rating for the arrester.

The temporary overvoltage is a maximum line-to-ground voltage of 181 kV for less than 1 second. The

TOV is evaluated to determine if adjustments are to be made to the arrester selection. The per unit

applied voltage based on the MCOV rating is 181/140 = 1.29. Figure 5-39 indicates that 1.29 per unit

voltage may be applied to the arrester for more than 100 seconds. The magnitude and duration of the

TOV do not warrant increasing the MCOV rating of the arrester.

Figure 5-41 indicates the insulation coordination for the 230 kV transformer protected with a typical

metal oxide arrester. The protection curves for the selected transformer BILs are plotted along with the

applicable points for the 140 kV MCOV arrester. The discharge current voltage levels and the switching

surge voltage levels are indicated. The protective margins for the BILs and the surge levels are indicated.

The protective ratios realized by the protective levels of the arrester substantially exceed the

recommended ratios of 20 percent for the front-of-wave and lightning impulse levels, and 15 percent for

the switching surge level.

Figure 5-42 shows curves for a 152 kV MCOV surge arrester with a corresponding duty-cycle rating of

192 kV, the same as the example used for the silicon-carbide arrester. The protective ratios realized by

the protective levels of the arrester substantially exceed the recommended ratios of 20 percent for the

front-of-wave and lightning impulse levels, and 15 percent for the switching surge level.
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Note: ** MCOV Peak Value: 152 x 2 = 215 kV

Figure 5-41: Typical Volt–Time Curves for Coordination of 152 kV MCOV Metal Oxide Surge Arrester Protective Levels

with Insulation Withstand Strength
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Note: ** MCOV Peak Value: * 140 x 2 = 198 kV

Figure 5-42: Typical Volt-Time Curves for Coordination of 140 kV MCOV Metal Oxide Surge Arrester

Protective Levels with Insulation Withstand Strength
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Substantial improvement in protective margins is realized with the use of metal oxide arresters.

Protection provided by two ratings of arresters is shown: 192 kV, which corresponds to the arrester rating

in Figure 5-35, and a 172 kV arrester, which corresponds to an MCOV rating of 140 kV, the minimum

recommended rating for the 230 kV voltage class.

5.8.8 Location

5.8.8.1 General: In general, surge arresters should be located at or near the main transformers on

both the high- and low-voltage sides. It may be desirable to also locate arresters at the line entrances or,

in some cases, on a bus that may be connected to several lines. They should be located to give maximum

possible protection to all major substation equipment.

In many cases, the arresters protecting the main transformer may be mounted directly on the transformer.

Lightning strokes can produce surges with steep wave fronts, voltage gradients, reflections, or oscillations

and high rates of rise of current, which can result in large differences in the line-to-ground voltage

between even closely spaced points. It is extremely important to locate the arresters as close as practical

to the apparatus requiring protection. The arrester lead length should be kept as short as practical. If

possible, the arrester should be connected directly to the jumper connecting the equipment to the system.

Following is a general guide for determining maximum separation distances between arrester lead tap and

transformer, considering the effect of arrester lead length.

5.8.8.2 Arrester Separation Distance and Lead Length

5.8.8.2.1 Impressed Voltage: The voltage impressed on the substation transformer after arrester

operation may be much higher than the arrester discharge voltage if either arrester separation distance (S)

or lead length (L) is excessive. Consequently, these factors have to always be considered in applying

arresters. Application curves have been developed to facilitate this.

5.8.8.2.2 Separation Distance: Arrester separation distance (S) is defined as the distance from the line

arrester lead junction to the transformer bushing. Voltage reflections result when the discharge voltage

traveling as a wave arrives at the transformer. If the arrester is very close to the transformer, these

reflections are cancelled almost instantaneously by opposite polarity reflections from the arrester. As the

separation distance increases, the cancellation becomes less and less effective, and the voltage at the

transformer may increase to almost twice the arrester discharge voltage.

5.8.8.2.3 Lead Length: Arrester lead length (L) is defined as the total length of the conductor from the

junction of the surge arrester lead with the line or transformer circuit to physical ground, but not including

the length of the arrester itself. When the arrester discharges, surge current flows to ground over the lead

length. The resulting voltage drop, L di/dt, is proportional to the lead length and adds to the arrester

discharge voltage.

5.8.8.2.4 Surge Voltage Increase: The increase in surge voltage due to separation distance and lead

length may be evaluated by the method given in AIEE Transactions Paper 63-229. It will be satisfactory,

however, to use the application curves from this reference, which are reproduced as Figures 5-43, 5-44,

and 5-45, to determine maximum lead lengths and separation distances for high-side arresters, provided

that modern arresters are used. For this purpose, any arrester manufactured in the United States during or

after 1960 may be considered modern.
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Figure 5-43: Maximum Safe Separation Distance of Lightning Arresters from Protected Equipment—

Nominal System Voltage 23 kV Through 46 kV (L = Arrester Lead Length, S = Separation).

Ref. IEEE Std. C62.22-1991. Copyright © 1991. IEEE. All rights reserved.
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Figure 5-44: Maximum Safe Separation Distance of Lightning Arresters from Protected Equipment—

Nominal System Voltage 69 kV Through 138 kV (L = Arrester Lead Length, S = Separation).

Ref. IEEE Std. C62.22-1991. Copyright © 1991. IEEE. All rights reserved.
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Figure 5-45: Maximum Safe Separation Distance of Lightning Arresters from Protected Equipment—

Nominal System Voltage 161 kV Through 345 kV(L = Arrester Lead Length, S = Separation).

Ref. IEEE Std. C62.22-1991. Copyright © 1991. IEEE. All rights reserved.
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5.8.8.3 Special Situations

5.8.8.3.1 On smaller substations with high-side fuses, the arrester should be located on the line side of

the fuse so as to prevent the lightning discharge from passing through the fuse.

5.8.8.3.2 Arresters need not be installed on the line side of high-voltage air-break switches. However,

they should be connected close enough to protect the switch adequately when the switch is closed. Line

entrance gaps may be used on the line side for protection when the switch is open. See Section 5.8.9,

Protection at Line Entrances.

5.8.8.3.3 Arresters of the valve type may be installed on the low-voltage distribution bus. They

should be installed on the load side of the feeder overcurrent device (recloser, fuse, or circuit breaker) and

any related disconnecting switch.

5.8.8.3.4 Continuous metallic sheath cables from substation to overhead lines should be protected by

arresters at the junction, and should be grounded effectively at the base of the cable terminal structure and

directly to the cable sheath. If the overhead line is unshielded, additional protective devices may be

required a few spans before the junction.

The cable sheath should be bonded to the substation ground at the substation end. It may also be

necessary to install arresters at the substation equipment end if the cable is such that two times the

protection level of the junction arrester exceeds 80 percent of the substation BIL. This is due to reflection

at the equipment end.

5.8.8.3.5 On high-voltage wye-connected transformers with ungrounded neutral, voltage reflections at

the neutral can approach two times the voltage applied simultaneously at the line terminals. It is therefore

necessary to employ a surge arrester from neutral to ground to limit these surge voltages, especially if the

transformer has graded insulation. The rating of the arrester should be approximately 1.2 times the

normal line-to-neutral system voltage.

5.8.9 Protection at Line Entrances

Lightning wave fronts may approach 1000 kV/μs, resulting in a gradient of 3.3 kV/m difference in lineto-ground potential. Most, however, do not exceed 500 kV/μs, and this value is considered a basis for

good practice. At open circuit points, these waves are reflected back at nearly double the original rate of

rise, increasing the possibility of a flashover or equipment damage close to that point. It is apparent that

protection should be considered for the line entrances on large substations, especially where line breakers

and disconnect switches may be open, constituting dead-end reflections. Surge arresters will provide the

most effective means of protection, but line entrance gaps may be sufficient. Line entrance protective

gaps may be considered as an economical alternative to surge arresters at substation entrances of all

overhead lines 23 kV and above to provide additional protection for substation insulation under the

following conditions:

1. When steep front incoming surges would break down insulation near the line entrance or on the

bus (station arresters may be far too distant to provide adequate protection);

2. When part of the station insulation is isolated from protective influence of the station arresters

by switching; and

3. When the station arrester has been damaged or otherwise removed from service so that its

protection is not available
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Note that the operation of a gap places a fault on the system that has to be cleared by a circuit breaker,

recloser, or fuse, remote from the line end in question. The engineer, along with operations personnel,

should evaluate the suitability of this type of operation.

5.8.10 References

AIEE Transactions Paper 63-229, “Simplified Method for Determining Permissible Separation Between

Arresters and Transformers.”

ANSI Std. C84.1, “Voltage Ratings for Electric Power Systems and Equipment (60Hz).”

ANSI/IEEE Std. C62.2, “Guide for Application of Gapped Silicon-Carbide Surge Arresters for

Alternating-Current Systems.”

ANSI/IEEE Std. C62.92, “IEEE Guide for the Application of Neutral Grounding in Electrical Utility

Systems Part I – Introduction.”

IEEE Std. C62.1, “Standard for Gapped Silicon-Carbide Surge Arresters for Alternating-Current Power

Circuits.”

IEEE Std. C62.11, “Standard for Metal-Oxide Surge Arresters for Alternating-Current Power Circuits.”

IEEE Std. C62.22, “Guide for the Application of Metal Oxide Surge Arresters for Alternating-Current

Systems.”

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”

Westinghouse Electric Corp., Transmission and Distribution Reference Book , Pittsburgh: Westinghouse

Electric Corp., 1950.

5.9 AUTOMATIC CIRCUIT RECLOSERS

5.9.1 General

This section covers single- and three-phase alternating-current automatic circuit reclosers.

An automatic circuit recloser is a self-controlled protective device used to interrupt and reclose

automatically an alternating-current circuit through a predetermined sequence of opening and reclosing

followed by resetting, lockout, or hold closed. Figures 5-46 and 5-47 show single- and three-phase

reclosure, respectively.

5.9.1.1 Purpose: Reclosers are installed to provide maximum continuity of service to distribution

loads, simply and economically, by removing a permanently faulted circuit from the system or by instant

clearing and reclosing on a circuit subjected to a temporary fault caused by lightning, trees, wildlife, or

similar causes. Unlike fuse links, which interrupt either temporary or permanent faults indiscriminately,

reclosers are able to distinguish between the two types of faults, permanent and temporary. They give

temporary faults repeated chances to clear or to be cleared by a subordinate protective device. If the fault

is not cleared, the recloser recognizes the fault as permanent and operates to lock out or, in some

applications, hold closed (see Section 5.9.5.4).
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Figure 5-46: Typical Single-Phase Hydraulically Controlled Oil Circuit Breaker.

Courtesy of Cooper Power Systems.
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Figure 5-47: Recloser with Single-Phase Tripping and Three-Phase Lockout.

Courtesy of Cooper Power Systems.
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5.9.1.2 Application: Automatic circuit reclosers are used in distribution substations and on branch

feeders to protect distribution circuits and to switch them. (see Figure 5-48). Their proper application

requires a study of the load and short-circuit characteristics of both the protecting and the protected

equipment. This includes high-voltage fuses or other protection in the supply to a substation transformer

bank, a circuit breaker or reclosers at the distribution voltage supplying the feeder at the substation,

various line reclosers, sectionalizers, line fuses, the wire arc burn-down characteristic at the fault location,

ground resistance, etc. In selecting reclosers, it is recommended that the procedure outlined in ANSI

Std. C37.61, Paragraph 4.3, be followed.

Figure 5-48: Typical Line Diagram of Distribution Circuit Showing Application of Reclosers

5.9.1.3 Service Conditions: Reclosers are suitable for operation at their standard rating within an

ambient temperature range of –30oC to +40oC (–22oF to 104oF) and at altitudes not exceeding

1000 meters (3300 feet). They may be applied at higher or lower temperatures, hydraulic slowed at 32oF,

but performance may be affected and the manufacturer should be consulted regarding special

considerations for such applications. They also may be applied at altitudes higher than 1000 meters

(3300 feet), provided that corrections (reductions) are made in impulse insulation level, rated maximum

voltage, and rated continuous current. Correction factors (multipliers) are given in Table 5-59, Columns 3

and 4. Reclosers designed for standard temperature rise may be used above an altitude of 1000 meters
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(3300 feet) at normal current rating without exceeding ultimate standard temperature limits, provided that

the ambient temperature does not exceed the maximum +40oC limit reduced by the correction factor

given in Table 5-59, Column 5.

Table 5-59: Altitude Correction for Automatic Circuit Reclosers.

Ref. ANSI/IEEE Std. C37.60–1981, Table 1.

Copyright © 1981. IEEE. All rights reserved.

Altitude Correction Factor (Multiplier)

(1) (2) (3) (4) (5)

Feet Meters Voltage Rating Current Rating Ambient Temp.

3300 1000 1.00 1.00 1.00

4000 1200 0.98 099 0.99

5000 1500 0.95 0.99 0.98

10000 3000 0.80 0.96 0.92

16000 4900 0.63 0.93 0.85

The rated interrupting current, current-related required capabilities, and rated interrupting time are not

affected by altitude.

5.9.1.4 Standards: Applicable ANSI Standards (listed below) are comprehensive and valuable

references when automatic circuit reclosers (ACRs) are being considered. Consult RUS IP 202-1, “List

of Materials Acceptable for Use on Systems of RUS Electrification Borrowers,” for manufacturers’ types

of ACRs.

• ANSI/IEEE C37.60, “Requirements for Automatic Circuit Reclosers for Alternating-Current

Systems”

• ANSI C37.61, “Guide for the Application, Operation and Maintenance of Automatic Circuit

Reclosers”

5.9.2 Recloser Classifying Features

5.9.2.1 Single-Phase or Three-Phase: Both single- and three-phase reclosers are available to satisfy

application requirements.

5.9.2.1.1 Single-Phase Reclosers: Single-phase reclosers are used to protect single-phase lines, such as

branches or taps of a three-phase feeder. They can also be used on three-phase circuits where the load is

predominantly single phase. Thus, when a permanent phase-to-ground fault occurs, one phase can be

locked out while service is maintained to the remaining two-thirds of the system.

5.9.2.1.2 Three-Phase Reclosers: Three-phase reclosers are used where lockout of all three phases is

required for any permanent fault. They are also used to prevent single phasing of three-phase loads, such

as large three-phase motors. Three-phase reclosers have two modes of operation.

5.9.2.1.2.1 The first, single-phase trip and three-phase lockout, consists of three single-phase reclosers

mounted in a single tank, with mechanical interconnection for lockout only. Each phase operates
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independently for overcurrent tripping and reclosing. If any phase operates to lockout condition due to a

permanent fault, the mechanical linkage trips open the other two phases and locks them open. Thus,

extended single-phase energization of three-phase loads is prevented. This type of operation is provided

for smaller recloser types.

5.9.2.1.2.2 Larger reclosers make use of the second mode of operation: three-phase trip with threephase lockout. For any fault—single-phase-to-ground, phase-to-phase, or three-phase—all contacts

operate simultaneously for each trip operation. The three phases, mechanically linked together for

tripping and reclosing, are operated by a common mechanism.

5.9.2.2 Control Intelligence: The intelligence that enables a recloser to sense overcurrents, select

timing operation, time the tripping and reclosing functions, and finally lock out, is provided by its control.

There are two basic types of control schemes used: integral “hydraulic” control or “electronic” control

located in a separate cabinet. A recloser employs one of these controls.

5.9.2.2.1 Hydraulic Recloser Control: Hydraulic recloser control is used in single-phase reclosers and

in smaller ratings of three-phase reclosers. It is built as an integral part of the recloser. With this type of

control, an overcurrent is sensed by a trip-coil connected in series with the line. When the overcurrent

flows through the coil, a plunger is drawn into the coil to trip open the recloser contacts. Timing and

sequencing are accomplished by pumping oil through separate hydraulic chambers or ducts.

5.9.2.2.2 Electronic Recloser Control: Electronic recloser control is used with some single-phase

reclosers and larger three-phase reclosers. Compared to the hydraulic control, it is more flexible, more

easily adjusted, and more accurate. The electronic control, housed in a cabinet separate from the recloser,

conveniently permits changing timing, trip current levels, and sequences of recloser operations without

de-energizing or untanking the recloser. A wide range of accessories are available from metering

capabilities on some models to modifying the basic operation, solving many different application

problems.

Line current is sensed by special sensing current transformers in the recloser. The recloser and control are

connected by a multiconductor control cable that carries sensing transformer secondary currents to the

control and the necessary trip and reclose signals from the control to the recloser. A dc battery either

supplies the control or provides backup, ensuring adequate operating power under all fault conditions.

Most reclosers require an external ac source either to charge the dc battery or provide control power.

5.9.2.3 Tripping: Series coil and non-series coil tripping are characteristics of individual

classifications of reclosers.

5.9.2.3.1 Series Coil Tripping: Series coil tripping is used on hydraulically controlled single-phase

reclosers and three-phase reclosers. Sensing of fault current is provided by a series-connected solenoid

coil (magnetic actuator) that carries its rated line current. When a fault occurs, tripping is initiated by the

solenoid plunger. The plunger, normally held at rest by the closing springs, is pulled into the coil and

causes overtoggling of trip springs in the operating mechanism that opens the recloser contacts.

Tripping simultaneously charges closing springs that then close or reclose the recloser when the proper

closing signal is present, thus making the recloser ready for another tripping operation.

5.9.2.3.2 Non-Series Coil Tripping: Non-series coil tripping is used on some single-phase vacuum

reclosers and some three-phase reclosers. It may consist of a tripping solenoid, energized from an
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external power supply, that over-toggles tripping springs in the same way as performed by the series trip

solenoid. It may also consist of a tripping spring simply released by a small tripping solenoid also

externally energized. In both cases, the tripping spring is previously charged by a closing solenoid or

closing motor during a closing or reclosing operation of the recloser. Other technologies do not utilize

spring charging, relying on the solenoid to perform the tripping operation.

5.9.2.4 Closing: Various methods of closing and reclosing are available, depending on the recloser

selected.

5.9.2.4.1 Spring Closing: Spring closing is utilized on most single-phase and some three-phase

reclosers. In each case, the closing spring is charged during a previous tripping operation.

5.9.2.4.2 Solenoid Closing: Solenoid closing is utilized on some single-phase and some three-phase

reclosers. The solenoid coil may be high-voltage ac and connected line to grounded neutral or it may be

low-voltage dc energized from a battery. A low-voltage rectifier accessory is also available to permit use

of local ac power supply for closing. Some methods utilize solenoid closing to charge the tripping

springs in preparation for the next tripping operation.

5.9.2.4.3 Motor Closing: Motor closing is utilized on some three-phase reclosers. The motor charges

the closing springs and forces their overtoggle to close the recloser. The closing spring action

simultaneously charges the tripping springs. The motor is energized from an external power supply.

5.9.2.5 Interrupter Types: Reclosers utilize either oil, vacuum, or SF6 as the interrupting medium.

5.9.2.5.1 Oil Interruption: Oil interruption is utilized on most single-phase and some three-phase

reclosers. Reclosers utilizing oil for current interruption use the same oil for basic insulation. Most

reclosers with hydraulic control also use the same oil for timing and counting functions.

5.9.2.5.2 Vacuum Interruption: Vacuum interruption is utilized on a few single-phase and some threephase reclosers. It has the advantages of lower maintenance frequency and minimum external force

reaction during interruption. Some vacuum reclosers may utilize oil as the basic insulating medium,

depending on the recloser selected.

5.9.2.5.3 SF6 Interruption: SF6 interruption is utilized on some three-phase reclosers. In addition to

having the same advantages as vacuum interruption, SF6 is a better insulating medium than oil or air.

NOTE: The term “Type” is a manufacturer’s designation to identify each particular group or family of

reclosers that it produces. It covers the major classifying features and certain rating and performance

characteristics.

RUS IP 202-1 contains a listing of RUS accepted recloser manufacturers, some on conditional basis.

5.9.3 Recloser Ratings

Automatic circuit reclosers are rated in terms of various voltages, frequency, continuous current,

minimum tripping current, interrupting current, and making current. In operating a recloser, the

limitations imposed by a given recloser rating should not be exceeded in any respect; otherwise, excessive

maintenance or unsatisfactory operation may be experienced.
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5.9.3.1 Voltage Rating

5.9.3.1.1 Nominal Voltage : Nominal voltage specifies the nominal system voltage to which the

recloser is intended to be applied.

5.9.3.1.2 Rated Maximum Voltage: Rated maximum voltage indicates the highest voltage at which the

recloser is designed to operate. Voltage ratings of automatic circuit reclosers are shown in ANSI/IEEE

Std. C37.60, “IEEE Standard Requirements for Overhead, Pad Mounted, Dry Vault, and Submersible

Automatic Circuit Reclosers and Fault Interrupters for AC Systems,” (Tables 5-60, 5-61, and 5-62).

NOTE: Some reclosers can be operated at system voltages lower than rated voltage. Series coil,

hydraulically operated reclosers can be applied at a lower voltage without modification, and in such cases

may gain an increase in interrupting current capability. Non-series coil—shunt coil closing, spring

tripping—reclosers can be applied at a lower voltage by installing a closing coil of the appropriate system

voltage rating. No change is necessary if the closing coil is low voltage and is supplied from an external

ac or dc auxiliary power source. Consult manufacturers and their literature for proper application of

reclosers at voltages lower than rated voltage.

5.9.3.1.3 Rated Impulse Withstand Voltage: Rated impulse withstand voltage of reclosers is a

performance characteristic specified in ANSI/IEEE Std. C37.60 as a test requirement. This test

demonstrates the ability of the recloser to withstand lightning and other fast impulse voltages. The

voltage wave is a standard 1.2 x 50 μs wave and may be either positive or negative polarity.

5.9.3.2 Rated Frequency: The rated frequency of reclosers is 60 Hz. Consult the manufacturer if

operation at other frequencies is being considered.

5.9.3.3 Rated Continuous Current: The rated continuous current is the magnitude of current in rms

amperes that the recloser is designed to carry continuously. The present continuous current ratings of

automatic circuit reclosers are shown in ANSI/IEEE Std. C37.60, Tables 5-60, 5-61, and 5-62. In many

cases, the basic continuous current rating of a given recloser is limited by the series trip solenoid coil

rating installed in the recloser. Therefore, as load current requirement increases, it is only necessary to

replace the solenoid coil with one having a larger rating. See ANSI/IEEE Std. C37.60; Tables 5-63, 5-64,

and 5-65.
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Table 5-60: Rated Maximum Voltage, Rated Continuous Current, Rated Interrupting Current,

Rated Impulse Withstand Voltage, and Performance Characteristics of Oil Reclosers.

Ref. ANSI/ IEEE Std. C37.60-1981, Table 2. Copyright © 1981. IEEE. All rights reserved.

Current Ratings, Standard Operating Duty*

Amperes Percent of Interrupting Rating

Low-Frequency

Insulation Level

Withstand Test* kV

rms

15 – 20 45 - 55 90 - 100

Line No.

Nominal

System

Voltage

(kV) rms

Rated

Maximum

Voltage

(kV) rms

Rated

Impulse

Withstand

Voltage*

(kV)

Crest

1 min

Dry

10 s

Wet

Continuous,

60 Hz

Symmetrical

Interrupting**

at Rated

Maximum

Volts

Minimum

X/R

Number of

Unit

Operations

Minimum

X/R

Number of

Unit

Operations

Minimum

X/R

Number of

Unit

Operations

Total

Number of

Unit

Operations

Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9 Col. 10 Col. 11 Col. 12 Col. 13 Col. 14 Col. 15

Single-Phase Reclosers

1 14.4 15.0 95 35 30 50 1250 2 40 4 40 8 20 100

2 14.4 15.5 110 50 45 100 2000 2 32 5 24 10 12 68

3 14.4 15.5 110 50 45 280 4000 3 32 6 20 12 12 64

4 14.4 15.5 110 50 45 560 10000 4 28 8 20 15 10 58

5 24.9 27.0 150 60 50 100 2500 2 32 5 24 12 12 68

6 24.9 27.0 150 60 50 280 4000 3 32 6 20 13 12 64

7 34.5 38.0 150 70 60 560 8000 4 28 8 20 15 10 58

Three-Phase Reclosers

8 14.4 15.0 95 35 30 50 1250 2 40 4 40 8 20 100

9 14.4 15.5 110 50 45 100 2000 2 32 5 24 10 12 68

10 14.4 15.5 110 50 45 280 4000 3 32 6 20 12 12 64

11 14.4 15.5 110 50 45 400 4000 3 32 6 20 12 12 64

12 14.4 15.5 110 50 45 560 8000 3 28 7 20 14 10 58

13 14.4 15.5 110 50 45 560 16000 4 16 8 8 16 4 28

14 14.4 15.5 110 50 45 560 16000 4 28 8 20 16 10 58

15 14.4 15.5 110 50 45 1120 16000 4 28 8 20 16 10 58

16 24.9 27.0 150 60 50 100 2500 2 32 5 24 12 12 68

17 24.9 27.0 150 60 50 560 8000 4 28 8 20 15 10 58

18 24.9 27.0 150 60 50 1120 8000 4 28 8 20 15 10 58

19 24.9 27.0 150 60 50 560 12000 4 28 8 20 15 10 58

20 34.5 38.0 150 70 60 400 6000 4 28 8 24 15 10 62

21 34.5 38.0 150 70 60 560 16000 4 28 8 20 15 10 58

22 34.5 38.0 150 70 60 1120 12000 4 28 8 20 15 10 58

23 46.0 48.3 250 105 95 560 10000 4 28 8 20 15 10 58

24 69.0 72.5 350 160 140 560 8000 4 28 8 20 16 10 58

*These are performance characteristics specified as test requirements in this standard.

**See Table 3 [Table 5-63] for complete data on rated interrupting currents for reclosers using smaller series coil sizes or reduced minimum trip settings.
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Table 5-61: Rated Maximum Voltage, Rated Continuous Current, Rated Interrupting Current, Rated Impulse Withstand Voltage,

and Performance Characteristics of Reclosers with Vacuum Interrupters.

Ref. ANSI/ IEEE Std. C37.60-1981, Table 4. Copyright © 1981. IEEE. All rights reserved.

Current Ratings

(A) Standard Operating Duty*

Percent of Interrupting Rating

Low-Frequency

Insulation Level

Withstand Test*

kV rms 15 – 20 45 – 55 90 - 100

Line

No.

Nominal

System

Voltage,

kV rms

Rated

Maximum

Voltage,

kV rms

Rated

Impulse

Withstand

Voltage,*

kV Crest

1 min.

Dry

10 s

Wet

Continuous,

60 Hz

Symmetrical

Interrupting** at

Rated

Maximum

Volts

Minimum

X/R

Number of

Unit

Operations

Minimum

X/R

Number of

Unit

Operations

Minimum

X/R

Number of

Unit

Operations

Total

Number of

Unit

Operations

Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9 Col. 10 Col.

11 Col. 12 Col. 13 Col. 14 Col. 15

Single-Phase Reclosers

1 14.4 15.5 110 50 45 200 2000 2 52 5 68 10 18 138

Three-Phase Reclosers

2 14.4 15.5 110 50 45 200 2000 2 52 5 68 10 18 138

3 14.4 15.5 110 50 45 400 6000 3 48 7 60 14 16 124

4 14.4 15.5 110 50 45 560 12000 4 44 8 66 15 16 116

5 14.4 15.5 110 50 45 800 12000 4 44 8 56 15 16 116

6 14.4 15.5 110 50 45 560 16000 4 44 8 52 16 16 112

7 14.4 15.5 110 50 45 800 16000 4 44 8 52 16 16 112

8Δ 14.4 15.5 110 50 45 1120 16000 4 44 8 52 16 16 112

9 24.9 27.0 125 60 50 560 10000 3 44 7 56 14 16 116

10Δ 34.5 38.0 150 70 60 560 12000 4 44 8 56 15 16 116

* These are performance characteristics specified as test requirements in this standard.

**See Table 5 [Table 5-64] for complete data on rated interrupting currents for reclosers using smaller series coil sizes or reduced minimum trip settings.

Δ These lines have been approved as Suggested Standard for Future Design.

NOTE: The Standard operating duty represents half-life as measured by contact erosion. Refer to the manufacturer’s method for determining permissible contact

erosion.
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Table 5-62: Rated Maximum Voltage, Rated Continuous Current, Rated Interrupting Current, Rated Impulse Withstand Voltage and Performance

Characteristics of Pad-Mounted, Dry-Vault and Submersible Reclosers, and Non- Reclosing Fault Interrupters,

All with Vacuum Interrupters. Ref. ANSI/ IEEE Std. C37.60-1981, Table 6. Copyright © 1981. IEEE. All rights reserved.

Current Ratings, Standard Operating Duty*

(A) Percent of Interrupting Rating

Low-Frequency

Insulation Level

Withstand Test**

kV rms 15 – 20 45 - 55 90 - 100

Line

No.

Nominal

System

Voltage

(kV)

rms

Rated

Maximum

Voltage

(kV)

rms

Rated

Impulse

Withstand

Voltage

(kV)

Crest

1 min

Dry

10 s

Wet

Maximum

Continuous,

60 Hz

Symmetrical

Interrupting

at Rated

Maximum

V

Minimum

X/R

Number

of Unit

Operations

Minimum

X/R

Number

of Unit

Operations

Minimum

X/R

Number

of Unit

Operations

Total

Number

of Unit

Operations

Withstand

Test

Voltage

kV – dc

15 min.

Col. 1 Col. 2 Col. 3 Col. 4 Col. 5 Col. 6 Col. 7 Col. 8 Col. 9 Col. 10 Col. 11 Col. 12 Col. 13 Col. 14 Col. 15 Col. 16

Three-Phase Reclosers

SSFD 1 14.4 15.5 95 35 200 8000 1 44 2 56 4 16 116 53

SSFD 2 14.4 15.5 95 35 560 6000 3 48 7 60 14 16 124 53

3 14.4 15.5 95 35 560 12000 4 44 8 56 15 16 116 53

 SSFD 4 14.4 15.5 95 35 560 12000 1 44 2 52 4 16 112 53

SSFD 5 24.9 27.0 125 40 200 16000 1 44 2 52 4 16 112 78

6 24.9 27.0 125 40 560 10000 3 28 7 20 14 10 58 78

* These are performance characteristics specified as test requirements in this standard.

** See Table 7 [Table 5-65] for complete data on rated interrupting currents for reclosers using smaller series coil sizes or reduced minimum trip settings.

NOTE: This standard operating duty represents half-life as measured by contact erosion. Refer to manufacturer’s methods for determining permissible contact

erosion.
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Table 5-63: Continuous Current and Interrupting Current Ratings of Oil Reclosers.

Ref. ANSI/ IEEE Std. C37.60-1981, Table 3. Copyright © 1981. IEEE. All rights reserved.

Interrupting Current Rating in Amperes at Rated Maximum Voltage

Single-Phase Series Coil Reclosers Three-Phase Series Coil Reclosers

Recloser Line No. Recloser Line No.

1 2 3 4 5 6 7 8 9 10 11 12-17 16 20

Rated Maximum Voltage, kV

Continuous

Current

Rating (A) 15.0 15.5 15.5 15.5 27.0 27.0 38.0 15.0 15.5 15.5 15.5 15-27 27.0 34.0

 5 125 200 — — 200 — — 125 200 — — — 200 —

 10 250 400 — — 400 — — 250 400 — — — 400 —

 15 375 600 — — 600 — — 375 600 — — — 600 —

 25 625 1000 1500 — 1000 — — 625 1000 1500 1500 — 1000 1500

 35 875 1400 2100 — 1400 — — 875 1400 2100 2100 — 1400 2100

 50 1250 2000 3000 — 2000 3000 — 1250 2000 3000 3000 — 2000 3000

 70 — 2000 4000 — 2500 4000 — — 2000 4000 4000 — 2500 4200

 100 — 2000 4000 6000 2500 4000 6000 — 2000 4000 4000 6000 2500 6000

 140 — — 4000 8400 — 4000 8000 — — 4000 4000 8000 — 6000

 200 — — 4000 10 000 — 4000 8000 — — 4000 4000 8000 — 6000

 280 — — 4000 10 000 — 4000 8000 — — 4000 4000 8000 — 6000

 400 — — — 10 000 — — 8000 — — — 4000 8000 — 6000

 560 — — — 10 000 — — 8000 — — — — 8000 — —

Three-Phase Non-Series Coil Reclosers

Recloser Line No.

11 12 13 14 15 17 18 19 20 21 22 23 24

Rated Maximum Voltage, kV

Minimum

Trip

Setting

(A) 15.5 15.5 15.5 15.5 15.5 27.0 27.0 27.0 38.0 38.0 38.0 48.3 72.5

 100 3000 — — — — — — — 3000 3000 — 3000 3000

 140 4000 — — — — — — — 4200 4200 — 4200 4200

 200 4000 6000 6000 6000 — 6000 6000 6000 6000 6000 6000 6000 6000

 280 4000 8000 8400 8400 — 8000 8000 8400 6000 8400 8400 8400 8000

 400 4000 8000 12 000 12 000 12 000 8000 8000 12 000 6000 12 000 12 000 10 000 8000

 560 4000 8000 16 000 16 000 16 000 8000 8000 12 000 6000 16 000 12 000 10 000 8000

 800 4000 8000 16 000 16 000 16 000 8000 8000 12 000 6000 16 000 12 000 10 000 8000

1120 — 8000 16 000 16 000 16 000 8000 8000 12 000 — 16 000 12 000 10 000 8000

1600 — — — — 16 000 — 8000 — — — 12 000 — —

2240 — — — — 16 000 — 8000 — — — 12 000 — —

NOTE: For interrupting current ratings at other than rated voltage, consult the manufacturer. The interrupting current ratings of reclosers are not generally on a

constant kVA basis.
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Table 5-64: Continuous Current and Interrupting Current Ratings of Reclosers

with Vacuum Interrupters.

Ref. ANSI/ IEEE Std. C37.60-1981, Table 5. Copyright © 1981. IEEE. All rights reserved.

Interrupting Current Rating in Amperes at Rated Maximum Voltage

Single-Phase Series Coil Reclosers Three-Phase Series Coil

Reclosers

Recloser Line No. Recloser Line No.

1 2 4 9

Rated Maximum Voltage, kV Rated Maximum Voltage, kV

Continuous

Current

Rating,

Amperes 15.5 15.5 15.5 27.0

 5 200 200 — —

 10 400 400 — —

 15 600 600 — —

 25 1000 1000 — —

 35 1400 1400 — —

 50 2000 2000 3000 3000

 70 2000 2000 4200 4200

100 2000 2000 6000 6000

140 2000 2000 8400 8400

200 2000 2000 12000 10000

280 — — 12000 10000

400 — — 12000 10000

560 — — 12000 10000

Three-Phase Non-Series Reclosers

Recloser Line No.

3 4 5 6 7 8 9 10

Rated Maximum Voltage, kV

Minimum

Trip Setting,

Amperes 15.5 15.5 15.5 15.5 15.5 15.5 27.0 38.0

 100 3000 3000 3000 3000 — — 3000 3000

 140 4200 4200 4200 4200 — — 4200 4200

 200 6000 6000 6000 6000 — — 6000 6000

 280 6000 8400 8400 8400 — — 8400 8400

 400 6000 12 000 12 000 12 000 12 000 12 000 10 000 12 000

 500 6000 12000 12000 16000 16000 16000 10000 12000

 800 6000 12000 12000 16000 16000 16000 10000 12000

1120 — 12000 12000 16000 16000 16000 10000 12000

1600 — — 12000 — 16000 16000 — —

2240 — — — — 16000 — — —

NOTE: For interrupting current ratings at other than rated voltage, consult the manufacturer. The

interrupting current ratings of reclosers are not generally on a constant kVA basis.
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Table 5-65: Continuous Current and Interrupting Current Ratings of Pad-Mounted,

Dry-Vault, and Submersible Reclosers, and Non-Reclosing Fault Interrupters,

All with Vacuum Interrupters. Ref. ANSI/ IEEE Std. C37.60-1981, Table 7.

Copyright © 1981. IEEE. All rights reserved.

Interrupting Current Rating in Amperes at Rated Maximum

Voltage

Three-Phase Series Coil Reclosers

Recloser Line No.

1 2 3 4 5 6

Rated Maximum Voltage, kV

Continuous

Current

Rating

(A) 15.5 27.0

50 3000 3000

70 4200 4200

100 6000 6000

140 8400 8400

200 12000 10000

280 12000 10000

400 12000 10000

560 12000 10000

Three-Phase Non-series Coil Reclosers

Recloser Line No.

1 2 3 4 5 6

Rated Maximum Voltage, kV

Minimum

Trip Setting

(A)

15.5 15.5 15.5 15.5 27.0 27.0

100 6000 6000 3000 3000 3000 3000

140 8000 3000 4200 4200 4200 4200

200 8000 4200 6000 6000 6000 6000

280 8000 6000 8400 8400 8400 8400

400 8000 6000 12000 12000 12000 10000

560 -- 6000 12000 16000 16000 10000

800 -- 6000 12000 16000 16000 10000

1120 -- 6000 12000 16000 16000 10000

5.9.3.4 Rated Minimum Tripping Current

5.9.3.4.1 The rated minimum tripping current is the minimum current at which a magnetically operated

series coil recloser will perform a tripping operation. Standard tripping pickup is 200 percent of the

continuous current rating of the recloser coil. Some reclosers are adjustable above or below the standard

tripping pickup value.

5.9.3.4.2 The minimum tripping current for shunt trip hydraulically controlled reclosers is as described

for series reclosers. With electronically controlled reclosers, the minimum trip rating is variable and has

no relation to the rated continuous current. Information on specific reclosers should be obtained from the

manufacturer.

The differential between minimum trip and continuous current ratings normally provides sufficient

margin for load inrush current pickup after an extended outage on a feeder circuit.

5.9.3.5 Rated Interrupting Current: The rated interrupting current is the maximum rms symmetrical

current that a recloser is designed to interrupt under the standard operating duty, circuit voltage, and

specified circuit constants. See ANSI/IEEE Std. C37.60, Tables 5-60 through 5-65. This rating is stated

on the nameplate. It is based on the capability of reclosers to interrupt the corresponding asymmetrical
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Page 371

current in circuits having minimum X/R values as given in Column 13 of Tables 5-60, 5-61, and 5-62

with a normal frequency recovery voltage equal to the rated maximum voltage of the recloser.

Multiplying factors that produce the maximum rms value of asymmetrical current at one-half cycle

corresponding to the rated interrupting current can be found in ANSI/IEEE Std. C37.60-1981,

Section 5.6, “Rated Symmetrical Interrupting Current,” page 17.

5.9.3.6 Rated Making Current: The rated making current is the same value as the rated interrupting

current, including the corresponding asymmetry. The recloser has to be capable of closing and latching

closed against the rated making current and holding closed until a tripping sequence is initiated.

5.9.4 Construction

Most automatic circuit reclosers consist of five major components: tank, bushings, mechanism,

interrupter, and controls. Although Figures 5-46 and 5-47 refer to oil circuit reclosers, many reclosers

consist of the same basic components.

5.9.4.1 Tank: The tank is that part of the recloser that houses the interrupter and tripping and closing

mechanisms. The tank is usually made of steel and is rectangular for a three-phase recloser and

cylindrical for a single-phase recloser. The top is usually an aluminum casting that supports the various

components. Some new technologies do not utilize tanks. The interrupter may be enclosed in an epoxy

bushing while the operating mechanism is enclosed in a steel housing.

5.9.4.2 Bushings: The bushings are the insulating structures including through-conductors with

provision for mounting on the top of the recloser.

5.9.4.3 Operating Mechanism: The operating mechanism of an automatic circuit recloser provides

the power to open, close, reclose, lock out, or hold closed the main contacts. The tripping mechanism is

the device that releases the holding means and opens the main contacts. In most cases, the opening force

is furnished by springs that are charged by the closing mechanism. An operating mechanism is shown in

Figure 5-49.

The closing mechanism is a solenoid coil, springs, or a motor and gear arrangement. The closing force

serves to close the main contacts and at the same time charges the opening springs. The lockout

mechanism is the device that locks the main contacts in the open position following the completion of the

sequence of operation. The hold-closed mechanism is the device that holds the main contacts in the

closed position following the completion of a predetermined sequence of operation. It holds the main

contacts closed as long as current flows in excess of a predetermined value. When the current is reduced

below this value, the hold-closed mechanism resets to its initial position.

X/R is the ratio of reactance to resistance of a circuit at rated

frequency. The rms value of asymmetrical fault current at any

time after initiation of the fault is dependent upon the

instantaneous voltage existing at the moment the fault is

initiated and upon the decrement of the direct current

component, which is determined by the X/R value of the

circuit.
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Figure 5-49: Operating Mechanism with Housing Cover Removed.

Courtesy of Cooper Power Systems.

5.9.4.4 Interrupter: The interrupter is that part of the recloser that contains separable contacts that

operate within an interrupting unit. The physical configuration and method of interruption vary with

manufacturer and recloser classification.

5.9.4.5 Control: Reclosers are provided with sequence control devices and operation integrator to

change the recloser from instantaneous operations to time-delay operations and to lock out the recloser

after a prescribed number of operations. Individual tripping operations of a recloser can be made to

follow instantaneous or time-delay, time–current characteristics. Reclosers are normally set for one of the

following sequences of operations:

a. Four time-delay operations

b. One instantaneous operation followed by three time-delay operations

c. Two instantaneous operations followed by two time-delay operations

A number of different sequence control devices may be roughly classed into three types: hydraulic,

mechanical, or electronic. In the hydraulic type, an oil pump attached to the recloser plunger raises a trip

piston a certain distance with each operation of the recloser. This trip piston establishes the sequence of

fast and delayed tripping operations and eventually locks the recloser open. In the mechanical type, the

trip piston is mechanically operated by the lift rod one notch at a time to accomplish this sequencing. The

electronic type of control utilizes solid-state circuitry to provide the intelligence for performing all the

command functions or automatic operation. Consult manufacturers’ literature for ratings and available

arrangements of electronic components.
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5.9.5 Recloser Operation

When an overcurrent of sufficient magnitude flows through the trip coil or sensing current transformers,

the tripping action is initiated and the contacts are opened. The recloser contacts then reclose following a

predetermined length of time (see Figure 5-50 – ANSI/IEEE Std. C37.60-1981, Fig. 1). By the time the

recloser has reassessed the circuit, the sequence control device has moved to count the trip operation. If

the fault still persists on the circuit when the recloser closes, the tripping and reclosing sequence is

repeated a predetermined number of times, as established by the sequence control device, until the

recloser goes to either the lockout or the hold-closed position. If the fault has cleared from the circuit

during any open-circuit period, however, the recloser closes and remains closed, and the sequence control

device resets so that it is in position for the next sequence of operations (see Figure 5-51).

Figure 5-50: Unit Operation. Ref. ANSI/ IEEE Std. C37.60-1981, Figure 1.

Copyright © 1981. IEEE. All rights reserved.

5.9.5.1 Manual Tripping: An automatic circuit recloser can be tripped manually by moving the

manual-operating handle to the trip position by means of a hookstick, or by moving the control switch to

the trip position if the recloser is provided with remote control. If the recloser has a nonreclosing lever,

the nonreclosing lever should be pulled down as far as it will go in order to cut out the automatic

reclosing before the recloser is manually tripped.

5.9.5.2 Manual Closing: An automatic circuit recloser can be closed manually by moving the manualoperating handle to the close position by means of a hookstick or, if the recloser is provided with remote
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Figure 5-51: Recloser Operating Sequence Upon Occurrence of a Permanent Fault

control, by moving the control switch to the close position. If the recloser has a nonreclosing lever, the

nonreclosing lever should be pulled down as far as it will go in order to cut out the automatic reclosing

before the recloser is closed manually. After the automatic circuit recloser has been successfully closed,

the automatic reclosing should be placed in service.

5.9.5.3 Manual Reclosing After Lockout Operation: Many reclosers in service are designed to lock

out following a selected sequence of tripping and automatic reclosing operations. The theory behind this

type of application is that, if a fault is temporary, it will be cleared during the instantaneous operation of

the recloser. If the fault is permanent, the recloser goes into time-delay tripping operation and permits

sectionalizing devices, such as fuses beyond the recloser, to open and isolate the fault. If a permanent

fault should occur between the recloser and the next sectionalizing device out on the line, the recloser

then goes to lockout and isolates the fault.

When a recloser appears to be locked out, the operator is always faced with the possibility that the

recloser itself may have failed. The following procedure is recommended for reclosing of the recloser

after a lockout operation.

5.9.5.3.1 Make a careful visual inspection for evidence of distress such as throwing of oil or damaged

bushings.

5.9.5.3.2 Close the recloser with a hookstick, keeping the hook in the operating ring momentarily so

that the recloser can be opened manually in case local trouble or failure becomes evident. If no local

trouble develops and the recloser again locks out after going through its proper sequence, it should not be

reclosed again until the entire circuit on the load side to all sectionalizing devices has been patrolled and

cleared if necessary.
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5.9.5.4 Manual Reclosing After Hold-Closed Operation: The recloser that is designed for holdclosed operation performs much the same function as the recloser that goes to lockout. It is normally set

to trip instantaneously twice to permit a temporary fault to clear. If the fault is permanent, the recloser

latches closed to permit the sectionalizing device nearest the fault to operate and isolate the fault.

However, a fuse at the recloser opens the circuit when a permanent fault occurs between the hold-closed

recloser and the next sectionalizing device out on the line. The fuse in series with the hold-closed

recloser is normally installed on the supply side of the recloser so that it also protects against electrical

failure in the recloser itself. To reclose a recloser after a hold-closed operation, the following procedure

is recommended.

5.9.5.4.1 Make a careful visual inspection for evidence of distress such as throwing of oil or damaged

bushings.

5.9.5.4.2 If inspection under Section 5.9.5.4.1 indicates that everything is in order, the operator should

first open the recloser with a hookstick, and then replace the fuse and close the cutout to check the

recloser on the supply side. If everything is in order, the operator should open the series cutout and close

the recloser; then close the series cutout. If there is no local trouble and service is still not restored, then

the load side to all sectionalizing devices should be patrolled to determine the cause of the tripout.

5.9.5.5 Load Pickup: The inrush current experienced in closing a recloser after a lockout operation

may occasionally introduce some difficulties in getting the recloser to latch closed. The highest inrush

current can originate from automatic starting motors or magnetizing current of transformers; however,

these types of inrush currents are normally short lived (on the order of 3 to 30 cycles). Some makes of

reclosers may operate on the instantaneous trip due to this inrush current and may have to open and

automatically reclose, until the sequence of operation comes to the time-delay trip, before the recloser

will stay closed. Other makes of reclosers, when reclosed after lockout, do not operate on the

instantaneous trip but have one time-delay trip operation to lock out, which will normally override the

inrush current and pick up the load. A cold-load pickup accessory is available on electronic controls for

three-phase reclosers. This accessory temporarily increases the minimum pickup current to a sufficient

value (usually double) to override the cold-load inrush current and allow the recloser to latch closed.

Careful observation will indicate whether failure to hold the load is caused by a fault or by heavy

overload. Instant and perhaps violent action would indicate a fault, whereas some delay might mean

overload due to inrush current. In the latter case, sectionalizing to drop part of the load, rather than a

patrol, may be necessary. In any case, if nothing is found on patrol, then sectionalizing is indicated.

5.9.6 Maintenance and Inspection

5.9.6.1 Installation: Before installing a recloser, check for external mechanical damage, oil level (oilfilled reclosers), operating sequence as specified, and the record reading on the operation counter.

Periodic inspection and maintenance are essential to ensure efficient, trouble-free service of an automatic

circuit recloser. Once an automatic circuit recloser is installed, it should be placed on a periodic schedule

of test and inspection. Frequency of maintenance should be based on the manufacturer’s recommendations, elapsed time in service, and number of operations. Many of the new vacuum technologies do not

require the frequency of scheduled maintenance that traditional oil circuit reclosers do. Such test and

inspection should cover timing tests and checking of bushings for cracks and of the tank for oil leakage,

as well as recording the counter reading. Internal inspection should include contact maintenance or

replacement; a check of all gears, linkages, timing devices; test of the oil, etc.
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5.9.7 Mounting

Most reclosers, both single- and three-phase, are suitable for mounting on poles (see Figure 5-52) and

substation structures. Single-phase reclosers can be mounted singularly or in clusters. Three-phase

reclosers have mounting frames that are suitable for base mounting, pad-mount enclosure installation, or

modification for pole or substation structure mounting.

Figure 5-52: Mounted Recloser. Courtesy of Cooper Power Systems.

5.9.8 References

ANSI Std. C37.61, “IEEE Standard Requirements for Overhead, Pad Mounted, Dry Vault, and

Submersible Automatic Circuit Reclosers and Fault Interrupters for AC Systems.”

ANSI Std. C42.100, IEEE Standard Dictionary of Electrical and Electronic Terms.

ANSI/IEEE Std. C37.60, “Requirements for Automatic Circuit Reclosers for Alternating-Current

Systems.”

Electrical Distribution – System Protection, 3d ed. Cooper Power Systems, 1990.

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”

Shapleigh, D.R., “Economic Feeder Protection with Automatic Circuit Reclosers,” The Line 76(3): 17.
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5.10 INSTRUMENT TRANSFORMERS

5.10.1 General

This section applies to current and inductively coupled voltage transformers of types generally used in the

measurement of electricity and in the control of equipment associated with the transmission and

distribution of alternating current.

The primary function of an instrument transformer is stated in the definition provided in ANSI/IEEE

Std. C57.13: “An instrument transformer is a transformer that is intended to reproduce in its secondary

circuit, in a definite and known proportion, the current or voltage of its primary circuit with the phase

relations substantially preserved.”

Instrument transformers also provide insulation between the primary and secondary circuits and thus

simplify the construction of measuring devices and provide safety for personnel using those devices.

Occasionally, instrument transformers serve another duty as bus supports, especially at the higher

voltages where the cost of extra bus supports becomes significant. The manufacturer should always be

consulted in such applications to determine what externally applied forces the product can withstand.

If necessary, a voltage transformer may be used for supplying power rather than for measurement. In

such situations, it is usually possible to place burdens higher than the volt-ampere rating on the secondary

circuit without excessive heating and consequent shortening of life. The limit of such burden is known as

the Thermal Burden Rating, i.e., “The volt-ampere output that the transformer will supply continuously at

rated secondary voltage without causing the specified temperature limits to be exceeded.” The voltage

transformer’s accuracy of transformation will not be maintained for this type of use.

The primary national standard applicable to current and voltage transformers is ANSI/IEEE Std. C57.13,

“IEEE Standard Requirements for Instrument Transformers.” This standard covers all-important aspects,

including terminology, general requirements, ratings, burdens, accuracy, construction, and test code.

5.10.2 Service Conditions

The standard ratings of instrument transformers are based on operation at the thermal rating of the

instrument transformer for defined ambient temperature conditions, provided the altitude does not exceed

1000 meters (3300 feet).

Instrument transformers may be used at higher ambient temperatures, at altitudes higher than 1000

meters, or for other unusual conditions if the effects on performance are considered. Consult the

manufacturer for specific applications.

5.10.2.1 Altitude: Table 5-33 in Section 5.5.3.5 shows the altitude correction factors to be used to

account for the adverse effect of decreased air density on the insulation withstand capability. These

correction factors modify the standard insulation classes shown in Table 5-66. A higher standard BIL

may be required at high altitudes in order to obtain the insulation required for the voltage used.

The decreased air density at higher altitudes also affects heat dissipation and the permissible loading on

instrument transformers. Current transformers may be operated at altitudes greater than 1000 meters if

the current is reduced below rated current by 0.3 percent for each 100 meters the altitude exceeds
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Table 5-66: Basic Impulse Insulation Levels and Dielectric Tests

Ref. IEEE Std. C57.13-1993, Table 2. Copyright © 1993. IEEE. All rights reserved.

See Table 5-69 for current transformers with the same dielectric test requirements as power circuit

breakers.

Maximum

System

Voltage

(kV)

Nominal

System

Voltage

(kV)

BIL and

Full Wave

Crest

(kV) *

Chopped Wave

Minimum Time

to Crest

Flashover

(kV) & (μs)

Power Frequency

Applied Voltage

Test

(kV rms)

Wet 60 Hz

10 s

Withstand

(kV rms)**

Minimum

Creepage

Distance

 (in.) & (mm)

.66 .6 10 12 — 4 — — —

1.2 1.2 30 36 1.5 10 6‡ — —

2.75 2.4 45 54 1.5 15 13‡ — —

5.6 5 60 69 1.5 19 20‡ — —

9.52 8.7 75 88 1.6 26 24‡ — —

15.5 15 95 110 1.8 34 30‡ — —

15.5 15 110 130 2 34 34 11 (279)

25.5 25 125 145 2.25 40 36‡ 15 (381)

25.5 25 150 175 3 50 50 17 (432)

36.5 34.5 200 230 3 70 70 26 (660)

48.3 46 250 290 3 95 95 35 (890)

72.5 69 350 400 3 140 140 48 (1220)

121 115 450 520 3 185 185 66 (1680)

121 115 550 630 3 230 230 79 (2010)

145 138 650 750 3 275 275 92 (2340)

169 161 750 865 3 325 315 114 (2900)

242 230 900 1035 3 395 350 140 (3500)

242 230 1050 1210 3 460 445 170 (4320)

362 345 1300 1500 3 575 — 205 (5210)

550 500 1675 1925 3 750 — 318 (8080)

550 500 1800 2070 3 800 — 318 (8080)

800 765 2050 2360 3 920 — 442 (11200)

* The selection of the lower BIL for a given nominal system voltage for a marked ratio in Tables 5-73 through 5-77

also reduces other requirements as tabulated above. The acceptability of these reduced requirements should be

evaluated for the specific instrument transformer design and application.

** For test procedures, see IEEE Std. 21-1976.

‡ These values are requirements for distribution transformer bushings in IEEE C57.12.00-1993.

1000 meters. Voltage transformers may be operated at higher altitudes only after consultation with the

manufacturer.

5.10.2.2 Temperature: Table 5-67 provides the limits of temperature rise for instrument

transformers, including the average winding temperature and hottest-spot winding temperature rises.

For 30oC average ambient temperature conditions, the temperature of the cooling air (ambient

temperature) does not exceed 40oC (104oF), and the average temperature of the cooling air for any

24-hour period does not exceed 30oC.

Instrument transformers may also be rated for 55oC ambient temperature for use inside enclosed

switchgear, provided the ambient temperature of the cooling air on the inside of enclosed switchgear does

not exceed 55oC. See ANSI Std. C37.20, “Switchgear Assemblies including Metal-Enclosed Bus,” and

NEMA Std. SG5, “Power Switchgear Assemblies,” for further information.
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Table 5-67: Limits of Temperature Rise.* Ref. IEEE Std. C57.13-1993, Table 4.

Copyright © 1993. IEEE. All rights reserved.

30°C Ambient 55°C Ambient

Type of

Instrument

Transformer

Average

Winding

Temperature

Rise

Determined by

Resistance

Method (°C)

Hottest-Spot

Winding

Temperature

Rise (°C)†

Average

Winding

Temperature

Rise

Determined by

Resistance

Method (°C)

Hottest-Spot

Winding

Temperature

Rise (°C)

55°C Rise 55‡ 65 30 40

65°C Rise 65‡ 80 40 55

80°C Rise Dry-Type 80 110 55 85

* Temperature rise of current transformers that are a part of high-voltage power circuit breakers or power

transformers shall be in accord with ANSI C37.04-1979 or IEEE C57.12.00-1993, respectively.

† Temperature rise of other metallic parts shall not exceed these values.

‡ Temperature rise at the top of the oil in sealed transformers shall not exceed these values.

Current transformers designed for 55oC temperature rise above 30oC ambient temperatures are given a

continuous-thermal-current rating factor (RF). The RF is multiplied by the rated current to indicate the

current that can be carried continuously without exceeding the standard temperature limitations. Figure 5-53 shows the permissible loading for given average cooling air temperatures and RFs. As an

example, a current transformer with an RF of 1.5 could be used at 150 percent of rated current at 30oC

average ambient temperature and 100 percent at 60oC average ambient temperature without exceeding the

temperature limitations of the current transformer.

Voltage transformers can be operated at higher ambient temperatures only after consultation with the

manufacturer.

5.10.3 Accuracy

To be a useful part of a measurement system, instrument transformers have to change the magnitude of

the voltage or current that is being measured without introducing any unknown errors of measurement

into the system. The accuracy of transformation should, therefore, be either a known value so that the

errors can be included in the computation of the overall measurement, or the errors have to be within the

limits of a specified small value so they may be disregarded.

The accuracy obtainable with an instrument transformer depends on its design, circuit conditions, and the

burden imposed on the secondary. Accuracy is measured in terms of its true value and phase angle under

specified operating conditions.

5.10.3.1 Accuracy Classes for Metering Service: Accuracy classes for metering service have been

established that limit the transformer correction factor (TCF) to specified values when the metered load

has a power factor of 0.6 lagging to 1.0. The standard accuracy classes for metering service and

corresponding TCF limits for current and voltage transformers are shown in Table 5-68. Higher accuracy

classes (e.g., 0.15) are available from some manufacturers.
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Figure 5-53: 55°C Rise Current Transformer Basic Loading Characteristics (in Air).

Ref. IEEE Std. C57.13-1993, Figure 1.

Copyright © 1993. IEEE. All rights reserved.

Table 5-68: Standard Accuracy Class for Metering Service and Corresponding Limits of

Transformer Correction Factor (0.6 to 1.0 Power Factor (Lagging) of Metered Load).

Ref. IEEE Std. C57.13-1993, Table 6. Copyright © 1993. IEEE. All rights reserved.

Voltage Transformers Current Transformers

(At 90 to 100 Percent

Rated Voltage) At 100% Rated Current* At 10% Rated Current Metering

Accuracy

Class Minimum Maximum Minimum Maximum Minimum Maximum

0.3 0.997 1.003 0.997 1.003 0.994 1.006

0.6 0.994 1.006 0.994 1.006 0.988 1.012

1.2 0.988 1.012 0.988 1.012 0.976 1.024

* For current transformers the 100 percent rated current limit also applies at the current corresponding to

the continuous thermal current rating factor.
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5.10.3.2 Transformer Correction Factor: The transformer correction factor for a current or voltage

transformer is the ratio correction factor (RCF) multiplied by the phase angle correction factor for a

specified primary circuit power factor.

5.10.3.3 Ratio Correction Factor: The ratio correction factor is the ratio of the true ratio to the

marked ratio.

5.10.3.4 Phase Angle Correction Factor: The phase angle correction factor is the ratio of the true

power factor to the measured power factor. It is a function of both the phase angles of the instrument

transformers and the power factor of the primary circuit being measured.

The phase angle correction factor corrects for the phase displacement of the secondary current or voltage,

or both, due to the instrument transformer phase angles.

Phase angle of an instrument transformer is the phase displacement, in minutes, between the primary and

secondary values.

5.10.4 Secondary Burdens

As defined in ANSI/IEEE Std. C57.13, burden for an instrument transformer is “that property of the

circuit connected to the secondary winding that determines the active and reactive power at the secondary

terminals. The burden is expressed either as total ohms impedance with the effective resistance and

reactive components, or as the total volt-amperes and power factor at the specified value of current or

voltage, and frequency.”

The burden on the secondary circuit of an instrument transformer affects the accuracy of the device.

Accordingly, the burdens of the various meters and other instruments on the secondary have to be known.

This information is usually obtained from data sheets issued by the manufacturers.

For many purposes, such as when the burdens are known to be well within the rated burden capability of

the transformer, or when accuracy is not a concern, it is sufficient to add arithmetically the volt-ampere

burden of the individual devices. If the burden is expressed as an impedance value, the volt-ampere

burden can be calculated from the relationship expressed in Equation 5-10:

Equation 5-10

VA = E2/Zb

Where:

E = Voltage drop across the burden

Zb = Burden impedance

For more accurate purposes, and when the actual burdens approach the limits of the burden rating, the

total burden should be determined by adding the individual burdens vectorially (taking power factors into

account).

5.10.5 Construction

All instrument transformers have external terminals or leads to which the high-voltage or primary circuit

and the secondary circuits are connected. These terminals are marked to indicate the polarity of the
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windings.

When letters are used to indicate polarity, the letter H shall be used to distinguish the terminals of the

primary winding. The letters X, Y, Z, W, V, U are used to identify the terminals of up to six secondary

windings, respectively.

In addition to the letters, each terminal is numbered (e.g., H1, H2, X1, X2). Letters followed by the same

number are of the same polarity.

If multiple primary windings are provided, the H terminals are numbered with consecutive pairs of

numbers (H1-H2, H3-H4, etc.). The odd-numbered terminals are of the same polarity.

When taps are provided in the secondary windings, the terminals of each winding are numbered

consecutively (X1, X2, X3, etc.). The lowest and highest numbered terminals indicate the full winding

with intermediate numbers indicating the taps. When the X1 terminals are not in use, the lower number

of the two terminals used is the polarity terminal.

5.10.6 Current Transformers

A current transformer is an instrument transformer intended to have its primary winding connected in

series with the conductor carrying the current to be measured or controlled. The ratio of primary to

secondary current is roughly inversely proportional to the ratio of primary to secondary turns and is

usually arranged to produce either five amperes or one ampere (IEC Standard) in the full tap of the

secondary winding when rated current is flowing in the primary.

Current transformers can be included in two general categories: metering service and relay service. As a

rule, current transformers designed for metering service should not be used for relay applications or

system protection. Likewise, current transformers designed for relay service should not be used for highaccuracy metering applications.

Current transformers designed for relay service are fabricated with large cores, which allows the current

transformer to replicate the primary current during fault (high primary current) conditions. The large core

requires a high exciting current, which limits the accuracy of the current transformer, especially for low

primary currents.

Current transformers designed for metering service have smaller cores with small or negligible exciting

currents, which enables the current transformer to be highly accurate at normal load currents. However,

the smaller core saturates (secondary current is not a replica of the primary current) at currents slightly

above rated current. A current transformer designed for metering service may not reliably operate

protective devices during fault conditions.

Current transformers can be supplied with single-ratio, dual-ratio, or multi-ratio secondary windings. A

multi-ratio current transformer is one from which more than one ratio can be obtained by the use of taps

on the secondary winding.

5.10.6.1 Types: Various types of current transformers are available. Figures 5-54 and 5-55 display

several types of current transformers.
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Figure 5-54: Bushing, Window, and Wound-Type Current Transformers.

Courtesy of Kuhlman Electric – Instrument Transformer Division, Versailles, Kentucky.
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Figure 5-55: High-Voltage Current Transformers.

Courtesy of Haefely Trench, Scarborough, Ontario, Canada
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5.10.6.1.1 Bar: A bar-type current transformer is one that has a fixed, insulated straight conductor in

the form of a bar, rod, or tube that is a single primary turn passing through the magnetic circuit and that is

assembled to the secondary, core, and winding.

5.10.6.1.2 Bushing: A bushing-type current transformer is one that has a round core and a secondary

winding insulated from and permanently assembled on the core but has no primary winding or insulation

for a primary winding. This type of current transformer is for use with a fully insulated conductor as the

primary winding.

5.10.6.1.3 Double-Secondary: A double-secondary current transformer is one that has secondary coils

each on a separate magnetic circuit with both magnetic circuits excited by the same primary winding.

Multiple-secondary (three or more) current transformers are also manufactured.

5.10.6.1.4 Window/Donut: A window- or donut-type current transformer is one that has a secondary

winding insulated from and permanently assembled on the core, but has no primary winding as an integral

part of the structure. Complete or partial insulation is provided for a primary winding in the window

through which one or more turns of the line conductor can be threaded to provide the primary winding.

5.10.6.1.5 Wound: A wound-type current transformer is one that has a fixed primary winding

mechanically encircling the core; it may have one or more primary turns. The primary and secondary

windings are completely insulated and permanently assembled on the core as an integral structure.

5.10.6.1.6 Others: Other types are available in addition to those listed. Descriptions can be found in

manufacturers’ literature.

5.10.6.2 Ratings: Ratings are used to specify the operating characteristics and construction of the

current transformer. The following paragraphs provide the terms used to express the ratings for current

transformers. ANSI/IEEE Std. C57.13 is a source of additional information for some ratings.

5.10.6.2.1 BILs: Basic impulse insulation levels (BILs) in terms of full wave test voltages, nominal

system voltages, and maximum line-to-ground system voltages are shown in Tables 5-66 and 5-69.

Table 5-69 also provides the BILs, maximum system voltage, and maximum line-to-ground voltages for

applications requiring current transformers to have the same dielectric test requirements as power circuit

breakers.
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Table 5-69: Basic Impulse Insulation Levels and Dielectric Tests for Current Transformers with the

Same Dielectric Test Requirements as Outdoor Power Circuit Breakers.*

Ref. IEEE Std. C57.13-1993, Table 3. Copyright © 1993. IEEE. All rights reserved.

Low Frequency (kV, rms) Impulse Test 1.2 x 50 μs Wave (kV, Crest)†

Minimum

Creep

Distance

Rated

max.

1 min.

dry 10 s wet

Full wave

withstand

Interrupter

full wave

2 μs

withstand

3 μs

withstand

Switching

impulse

insulation

level (mm) (in.)

121 260 230 550B‡ 412 710 632 Not req’d 1780 70

145 310 275 650B 488 838 748 Not req’d 2130 84

169 365 315 750B 552 968 862 Not req’d 2490 93

242 425 350 900B 675 1160 1040 Not req’d 3560 140

362 555 Not req’d 1300B 975 1680 1500 825 5310 209

550 860 Not req’d 1800B 1350 2320 2070 1175 8080 318

800 960 Not req’d 2050B 1540 2640 2360 1425 11200 442

*See IEEE Std. C37.09-1979 for impulse and applied potential test procedures.

†No flashovers are permitted on current transformers.

‡

The letter “B” values are established by ANSI C37.06-1987 for current transformers that have the same

requirements as power circuit breakers.

5.10.6.2.2 Current Ratings: Current ratings are shown in Table 5-70 (for other than bushing type) and

Table 5-71 (multi-ratio bushing type).

Table 5-70: Ratings for Current Transformers with One or Two Ratios.

Ref. IEEE Std. C57.13-1993, Table 7. Copyright © 1993. IEEE. All rights reserved.

Current Ratings (A)

Single Ratio

Double Ratio With

Series-Parallel

Primary Windings

Double Ratio with

Taps in

Secondary Winding

10:5 800:5 25 x 50:5 25 / 50:5

15:5 1200:5 50 x 100:5 50 / 100:5

25:5 1500:5 100 x 200:5 100 / 200:5

40:5 2000:5 200 x 400:5 200 / 400:5

50:5 3000:5 400 x 800:5 300 / 600:5

75:5 4000:5 600 x 1200:5 400 / 800:5

100:5 5000:5 1000 x 2000:5 600 / 1200:5

200:5 6000:5 2000 x 4000:5 1000 / 2000:5

300:5 8000:5 1500 / 3000:5

400:5 12 000:5 2000 / 4000:5

600:5
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Table 5-71: Current Transformer Ratings, Multi-Ratio Type.

Ref. IEEE Std. C57.13-1993, Table 8. Copyright © 1993. IEEE. All rights reserved.

Current Ratings

(A)

Secondary

Taps

Current Ratings

(A)

Secondary

Taps

600:5 3000:5

50:5 X2 - X3 300:5 X3 - X4

100:5 X1 - X2 500:5 X4 – X5

150:5 X1 - X3 800:5 X3 – X5

200:5 X4 – X5 1000:5 X1 – X2

250:5 X3 – X4 1200:5 X2 – X3

300:5 X2 - X4 1500:5 X2 – X4

400:5 X1 – X4 2000:5 X2 – X5

450:5 X3 – X5 2200:5 X1 – X3

500:5 X2 – X5 2500:5 X1 – X4

600:5 X1 – X5 3000:5 X1 – X5

1200:5 4000:5

100:5 X2 – X3 500:5 X1 – X2

200:5 X1 – X2 1000:5 X3 – X4

300:5 X1 – X3 1500:5 X2 – X3

400:5 X4 – X5 2000:5 X1 – X3

500:5 X3 – X4 2500:5 X2 – X4

600:5 X2 – X4 3000:5 X1 – X4

800:5 X1 – X4 3500:5 X2 – X5

900:5 X3 – X5 4000:5 X1 – X5

1000:5 X2 – X5

1200:5 X1 – X5

2000:5 5000:5

300:5 X3 – X4 500:5 X2 – X3

400:5 X1 – X2 1000:5 X4 – X5

500:5 X4 – X5 1500:5 X1 – X2

800:5 X2 – X3 2000:5 X3 – X4

1100:5 X2 – X4 2500:5 X2 – X4

1200:5 X1 – X3 3000:5 X3 – X5

1500:5 X1 – X4 3500:5 X2 – X5

1600:5 X2 – X5 4000:5 X1 – X4

2000:5 X1 – X5 5000:5 X1 – X5

5.10.6.2.3 Standard Burdens: Standard burdens for current transformers are shown in Table 5-72.

The first five burdens listed are burdens for which metering accuracy classes have been assigned, and the

last four are for relay accuracy.

5.10.6.2.4 Accuracy Ratings: Accuracy ratings are given for each standard burden for which the

current transformer is designed. Table 5-68 lists the accuracy classes and corresponding limits for

transformer correction factors for current transformers for metering service.

For example, the accuracy rating of a current transformer for metering service might be 0.3B-0.1 and

B-0.2, and 0.6B-0.5. Based on these ratings, the transformer will maintain 0.3 accuracy class limits for

standard burdens of B-0.1 and B-0.2 and maintain 0.6 accuracy class limits for a standard burden of

B-0.5. The standard metering burdens, with the characteristics shown by Table 5-72, are 0.1, 0.2, 0.5,

0.9, and 1.8.
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Table 5-72: Standard Burdens for Current Transformers with 5 A Secondaries.*

Ref. IEEE Std. C57.13-1993, Table 9. Copyright © 1993. IEEE. All rights reserved.

Burden

Designation†

Resistance

(Σ)

Inductance

(mH)

Impedance

(Σ)

VoltAmperes

(at 5 A)

Power

Factor

Metering Burdens

B-0.1 0.09 0.116 0.1 2.5 0.9

B-0.2 0.18 0.232 0.2 5.0 0.9

B-0.5 0.45 0.580 0.5 12.5 0.9

B-0.9 0.81 1.04 0.9 22.5 0.9

B-1.8 1.62 2.08 1.8 45.0 0.9

Relaying Burdens

B-1 0.5 2.3 1.0 25 0.5

B-2 1.0 4.6 2.0 50 0.5

B-4 2.0 9.2 4.0 100 0.5

B-8 4.0 18.4 8.0 200 0.5

* If a current transformer is rated at other than 5 A, ohmic burdens for specification and rating may be

derived by multiplying the resistance and inductance of the table by [5/(ampere rating)]

2

, the VA at rated

current and the power factor remaining the same.

† These standard burden designations have no significance at frequencies other than 60 Hz.

5.10.6.2.5 Relay Accuracy: Relay accuracy ratings (or classes) are designated by a classification and

a secondary voltage terminal rating as follows:

a. C or K classification means the transformer ratio can be calculated according to ANSI/IEEE

Std. C57.13, Paragraph 8.1.10. In other words, the true ratio of the transformer (primary

current to secondary current) can be readily determined for each application using the marked

ratio and typical excitation curves.

b. T classification means the transformer ratio have to be determined by test. The manufacturer

has to supply test data to determine performance.

c. The secondary terminal voltage rating is the voltage that the transformer will deliver to a

standard burden listed in Table 5-72 at 20 times normal secondary current (and also at any

current from 1 to 20 times rated current at any lesser burden) without exceeding 10 percent

ratio error.

For example, relay accuracy class C400 means that the ratio can be calculated and that the ratio error will

not exceed 10 percent at any current from 1 to 20 times normal secondary current if the burden does not

exceed 4.0 ohms (4.0 ohms x 5 amperes x 20 times normal current = 400 volts).

Standard secondary terminal voltage ratings are 10, 20, 50, 100, 200, 400, and 800 volts.

5.10.6.2.6 Tapped Secondary or Multi-Ratio Current Transformer: For current transformers with

tapped secondaries or multi-ratio secondaries, the accuracy class applies only to the full secondary

winding unless specifically stated otherwise. Performance on lower taps may be significantly reduced

and limited. Use of the lower taps should be avoided if possible.

5.10.6.2.7 Continuous Thermal Current Rating Factors: Continuous thermal current rating factors

shall be 1.0, 1.33, 1.5, 2.0, 3.0, or 4.0, based on 30oC ambient temperature.

5.10.6.2.8 Short-Time Current Ratings: Short-time current ratings (mechanical and thermal) are

described in ANSI/IEEE Std. C57.13, Paragraph 6.6. The ratings represent the short-time (typically
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1 second) primary current the current transformer can withstand with the secondary windings short

circuited without damage or exceeding temperature limitations.

5.10.6.3 Open-Circuit Secondary Voltage: Dangerously high voltages (more than 3500 volts for

Class 1) can exist at the open circuit of current transformer secondary circuits, and appropriate measures

have to be taken for safety and insulation withstand capability. Always short the secondary windings of

current transformers when not in use.

5.10.6.4 Application Data Required for Metering Service: The following information has to be

available for calculating the performance of current transformers for metering service:

• Typical ratio correction factor and phase angle curves for the standard burdens for which

accuracy ratings are assigned

• Mechanical and thermal short-time ratings

5.10.6.5 Application Data Required for Relaying Service: The following information has to be

available for calculating the performance of current transformers for relaying service:

• Relaying accuracy classification

• Mechanical and thermal short-time ratings

• Resistance of secondary winding to determine value for each published ratio

• For Class C and K transformers, typical excitation curves

• For Class T transformers, typical overcurrent ratio curves

5.10.7 Voltage Transformers

A voltage transformer or potential transformer is an instrument transformer intended to have its primary

winding connected in shunt with a power supply circuit, the voltage of which is to be measured or

controlled.

5.10.7.1 Types: There are several types of voltage transformers available. Figure 5-56 displays

several voltage transformers.

5.10.7.1.1 A cascade-type voltage transformer is a single high-voltage line terminal voltage

transformer with the primary winding distributed on several cores with the cores electromagnetically

coupled by coupling windings and the secondary winding on the core at the neutral end of the highvoltage winding. Each core of this type of transformer is insulated from the other cores and is maintained

at a fixed potential with respect to ground and the line-to-ground voltage.

5.10.7.1.2 A double-secondary voltage transformer is one that has two secondary windings on the

same magnetic circuit insulated from each other and the primary. Either or both of the secondary

windings may be used for measurements or control.

5.10.7.1.3 A grounded-neutral, terminal-type voltage transformer is one that has the neutral end of the

high-voltage winding connected to the case or mounting base.

5.10.7.1.4 An insulated-neutral, terminal voltage transformer is one that has the neutral end of the

high-voltage winding insulated from the case or base and connected to a terminal that provides insulation

for a lower voltage insulation class than required for the rated insulation class of the transformer.
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Figure 5-56: Voltage Transformers.

Courtesy of Kuhlman Electric, Instrument Transformer Division, Versailles, Kentucky.
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5.10.7.1.5 A single high-voltage line, terminal voltage transformer is one that has the line end of the

primary winding connected to a terminal insulated from ground for the rated insulation class. The neutral

end of the primary winding may be connected as described in Sections 5.10.7.1.3 or 5.10.7.1.4.

5.10.7.1.6 A two-high-voltage line, terminal voltage transformer is one that has both ends of the highvoltage winding connected to separate terminals that are insulated from each other, and from other parts

of the transformer, for the rated insulation class of the transformer.

5.10.7.2 Ratings: The following paragraphs describe the terms and figures used to express the ratings

of voltage transformers.

5.10.7.2.1 BILs in terms of full wave test voltages, primary voltage ratings, and marked ratios are

shown in Tables 5-73 through 5-77.

The standard voltage transformers listed in the tables are divided into Groups 1, 2, 3, 4, and 5.

Group 1: Designed for 100 percent of rated primary voltage across the primary winding when connected

line-to-line, line-to-ground, or line-to-neutral.

Group 2: Designed for line-to-line service, but may be used line-to-ground or line-to-neutral at a voltage

across the primary winding equal to the rated line-to-line voltage divided by 3 . This

restriction is due to insulation limitations from line to ground.

Group 3: Designed for line-to-ground service only and having two secondaries. The neutral terminal

may be an insulated or grounded type.

Group 4: Designed for line-to-ground service in indoor applications only. The neutral terminal may be

an insulated or grounded type.

Group 5: Designed for line-to-ground servic e only in outdoor applications. The neutral terminal may be

an insulated or grounded type. Similar to Group 3 except single ratio and includes lower

voltage classes.
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Table 5-73: Ratings and Characteristics of Group 1 Voltage Transformers.

Ref. IEEE Std. C57.13-1993, Table 10.

Copyright © 1993. IEEE. All rights reserved.

Group 1 voltage transformers are for application with 100 percent of

rated primary voltage across the primary winding when connected line-toline or line-to-ground. (For typical connections, see Figs 6A and 6B in IEEE

C57.13-1993.)

Group 1 transformers shall be capable of operation at 125 percent of

rated voltage on an emergency basis (this capability does not preclude the

possibility of ferroresonance), provided the burden, in volt-amperes at rated

voltage, does not exceed 64 percent of the thermal burden rating, without

exceeding the following average winding temperatures: 105°C for 55°C rise

types, 115°C for 65°C rise types, and 130°C for 80°C rise types. This will

result in a reduction of life expectancy.

Rated Primary Voltage for

Rated Voltage Line-to-Line

(V)

Marked

Ratio

Basic Impulse

Insulation Level

(kV Crest)

120 for 208Y 1:1 10

240 for 416Y 2:1 10

300 for 520Y 2.5:1 10

120 for 208Y 1:1 30

240 for 416Y 2:1 30

300 for 520 T 2.5:1 30

480 for 832Y 4:1 30

600 for 1040Y 5:1 30

2400 for 4160Y 20:1 60

4200 for 7280Y 35:1 75

4800 for 8320Y 40:1 75

7200 for 12 470Y 60:1 110 or 95

8400 for 14 560”Y 70:1 110 or 95

NOTE: Voltage transformers connected line-to-ground on an ungrounded

system cannot be considered to be grounding transformers and should not

be operated with the secondaries in closed delta because excessive

currents may flow in the delta.
Bulletin 1724E-300

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Table 5-74: Ratings and Characteristics of Group 2 Voltage Transformers.

Ref. IEEE Std. C57.13-1993, Table 11.

Copyright © 1993. IEEE. All rights reserved.

Group 2 voltage transformers are primarily for line-to-line service, and may

be applied line-to-ground or line-to-neutral at a winding voltage equal to the

primary voltage rating divided by 3 . (For typical connections, see

Figs. 6C and 6D in IEEE C57.13-1993.)

Rated Primary Voltage for

Rated Voltage Line-to-Line

(V)

Marked

Ratio

Basic Impulse

Insulation Level

(kV Crest)

120 for 120Y 1:1 10

240 for 240Y 2:1 10

300 for 300Y 2.5:1 10

480 for 480Y 4:1 10

600 for 600Y 5:1 10

2400 for 2400Y 20:1 45

4800 for 4800Y 40:1 60

7200 for 7200Y 60:1 75

12 000 for 12 000Y 100:1 110 or 95

14 400 for 14 400Y 120:1 110 or 95

24 000 for 24 000Y 200:1 150 or 125

34 500 for 34 500Y 300:1 200 or 150

46 000 or 46 000Y 400:1 250

69 000 for 69 000Y 600:1 350

NOTE: Voltage transformers connected line-to-ground on an ungrounded

system cannot be considered to be grounding transformers and should

not be operated with the secondaries in closed delta because excessive

currents may flow in the delta.
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Table 5-75: Ratings and Characteristics of Group 3 Outdoor Voltage Transformers.

Ref. IEEE Std. C57.13-1993, Table 12. Copyright © 1993. IEEE. All rights reserved.

Group 3 voltage transformers are for line-to-ground connection only and have two

secondaries. They may be insulated-neutral- or grounded-neutral-terminal type.

Ratings through 161 000 Grd Y/92 000 shall be capable of the 3 times rated

voltage (this does not preclude the possibility of ferroresonance) for 1 min. without

exceeding 175°C temperature rise for copper conductor or 125°C rise for EC aluminum.

Ratings 230 000 Grd Y /138 000 and above shall be capable of operation at 140 percent

of rated voltage with the same limitation of time and temperature. (For typical

connections, see Fig. 6E of IEEE C57.13-1993.) Group 3 transformers shall be capable

of continuous operation at 110 percent of rated voltage, provided the burden in voltamperes at this voltage does not exceed the thermal burden rating.

Rated Voltage

(V)

Marked

Ratio

Basic Impulse

Insulation Level

(kV Crest)

24 940 Grd Y/14 400 120/200 and 120/200:1 150 or 125

34 500 Grd Y/20 125 175/300 and 175/300:1 200

46 000 Grd Y/27 600 240/400 and 240/400:1 250

69 000 Grd Y/40 250 350/600 and 350/600:1 350

115 000 Grd Y/69 000 600/1000 and 600/1000:1 550 or 450

138 000 Grd Y/80 500 700/1200 and 700/1200:1 650 or 550

161 000 Grd Y/92 000 800/1400 and 800/1400:1 750 or 650

230 000 Grd Y/138 000 1200/2000 and 1200/2000:1 1050 or 900

345 000 Grd Y/207 000* 1800/3000 and 1800/3000:1 1300 or 1175

500 000 Grd Y/287 500* 2500/4500 and 2500/4500:1 1800 or 1675

750 000 Grd Y/431 250* 3750/6250 and 3750/6250:1 2050

 * The higher figures 362 000, 550 000, and 800 000 are the maximum rated primary

voltage values as designated for use with extra-high-voltage systems by the ANSI C92

Committee.

NOTES:

(1) The double voltage ratio is usually achieved by a tap in the secondary; in such cases

the nonpolarity terminal of the winding shall be the common terminal.

(2) Voltage transformers connected line-to-ground on an ungrounded system cannot be

considered to be grounding transformers and should not be operated with the

secondaries in closed delta because excessive currents may flow in the delta.
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Table 5-76: Ratings and Characteristics of Group 4 Indoor Voltage Transformers.

Ref. IEEE Std. C57.13-1993, Table 13. Copyright © 1993. IEEE. All rights reserved.

Group 4 voltage transformers are for line-to-ground connection only. They may be insulated-neutralor grounded-neutral-terminal type. (For typical connections of Group 4A, see Fig. 6f. For typical

connections of Group 4B, see Fig. 6g in IEEE C57.13-1993.)

Group 4 voltage transformers shall be capable of continuous operation at 110 percent of rated voltage,

provided the burden, in volt-amperes at this voltage, does not exceed the thermal burden rating. Group

4A voltage transformers shall be capable of operation at 125 percent of rated voltage on an emergency

basis (this capability does not preclude the possibility of ferroresonance), provided the burden, in voltamperes at rated voltage, does not exceed 64 percent of the thermal burden rating, without exceeding the

following winding temperatures: 105°C for 55°C rise types, 115°C for 65°C rise types, and 130°C for

80°C rise types. (This will result in a reduction of normal life expectancy.) The manufacturer may be

consulted for information about a possible higher rating.

Rated Primary Voltage for

Rated Voltage Line-to-Line

(V)

Marked

Ratio

Basic Impulse

Insulation Level

(kV Crest)

Group 4A: For Operation at Approximately

100 Percent of Rated Voltage

4160 Grd Y/2400 20:1 60

7200 Grd Y/4200 35:1 75

8320 Grd Y/4800 40:1 75

12 470 Grd Y/7200 60:1 110 or 95

14 560 Grd Y/8400 70:1 110 or 95

Group 4B: For Operation at Approximately

58 Percent of Rated Voltage

4160 Grd Y/4200 35:1 60

4800 Grd Y/4800 40:1 60

7200 Grd Y/7200 60:1 75

12 000 Grd Y/12 000 100:1 110 or 95

14 400 Grd Y/14 400 120:1 110 or 95

NOTE: Voltage transformers connected line-to-ground on an ungrounded system cannot be considered

to be grounding transformers and should not be operated with the secondaries in closed delta because

excessive currents may flow in the delta.
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Table 5-77: Ratings and Characteristics of Group 5 Outdoor Voltage Transformers.

Ref. IEEE Std. C57.13-1993, Table 14. Copyright © 1993. IEEE. All rights reserved.

 Group 5 voltage transformers are for line-to-ground connection only, and are for use outdoors on

grounded systems. They may be insulated-neutral- or grounded-neutral-terminal type. They shall be

capable of operation at 140 percent of rated voltage for 1 min. without exceeding 175°C temperature rise

for copper conductor or 125°C rise for EC aluminum conductor (this will result in a reduction of normal life

expectancy). (For typical connections see Fig. 6h in IEEE C57.13-1993.)

 Group 5 voltage transformers shall be capable of continuous operation at 110 percent of rated voltage,

provided the burden, in volt-amperes at this voltage, does not exceed the thermal burden rating. This

capability does not preclude the possibility of ferroresonance.

Rated Primary Voltage for

Rated Voltage Line-to-Line

(V)

Marked

Ratio

Basic Impulse

Insulation Level

(kV Crest)

7200 for 12 470 Gnd Y 60:1 110

8400 for 14 560 Gnd Y 70:1 110

12 000 for 20 800 Gnd Y 100:1 150 or 125

14 400 for 25 000 Gnd Y 120:1 150 or 125

20 125 for 34 500 Gnd Y 175:1 200 or 150

Typical primary connections for the voltage transformers of Groups 1, 2, and 3 are shown in Figure 5-57.

5.10.7.2.2 A voltage transformer shall be assigned an accuracy class rating (see ANSI/IEEE

Std. C57.13) for each of the standard burdens for which it is designed. For example, an accuracy rating

may be 0.3W and X, 0.6Y, and 1.2Z. The values 0.3, 0.6, and 1.2 indicate the accuracy class and

represent the percent deviation (maximum and minimum) from the rated voltage. The designations W, X,

Y, and Z are standard burdens.

Standard burdens for voltage transformers for accuracy rating purposes are given in Table 5-78. The

burdens are expressed in volt-amperes at a specified power factor at either 120 or 69.3 volts.

Table 5-78: Standard Burdens for Voltage Transformers.

Ref. IEEE Std. C57.13-1993, Table 15. Copyright © 1993. IEEE. All rights reserved.

Characteristics on Characteristics on Characteristics on

Standard Burdens* 120 V Basis 69.3 V Basis

DesignationVoltAmperesPower

Factor

Resistance

(Ω)

Inductance

(H)

Impedance

(Ω)

Resistance

(Ω)

Inductance

(H)

Impedance

(Ω)

W 12.5 0.10 115.2 3.04 1152 38.4 1.01 384

X 25 0.70 403.2 1.09 576 134.4 0.364 192

M 35 0.20 82.3 1.07 411 27.4 0.356 137

Y 75 0.85 163.2 0.268 192 54.4 0.0894 64

Z 200 0.85 61.2 0.101 72 20.4 0.0335 24

ZZ 400 0.85 30.6 0.0503 36 10.2 0.0168 12

* These burden designations have no significance except at 60 Hz.

NOTE: For rated secondary voltages from 108 V through 132 V or from 62.4 V through 76.2 V, the standard burdens for accuracy

tests within ±10% of rated voltage are defined by the characteristic burden impedances at 120 V or 69.3 V respectively. For other

rated secondary voltages, the standard burdens for accuracy tests within ±10% of rated voltage are defined by the characteristic

burden volt-amperes and power factor. The characteristic volt-amperes apply at rated secondary voltage and appropriate

impedances are required. When transformers with rated secondary volts from 108 V through 132 V are tested at secondary

voltages within ±10% of 1⁄2 times rated voltage, the standard burdens for accuracy tests are defined by the characteristic burdens

impedances at 69.3 V. When transformers with other rated secondary volts are to be tested at secondary voltages within ±10% of

1/13 times rated voltage, the standard burdens for accuracy tests are defined by the characteristic burden volt-amperes and power

factor. The characteristic volt-amperes apply at 1/13 times rated voltage, for a given standard burden; the burden impedances are

lower and the changes in accuracy resulting from burden current are greater than at rated voltage.
Bulletin 1724E-300

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Figure 5-57: Typical Primary Connections for Voltage Transformers.

Ref. IEEE Std. C57.13-1993, Figures 6 A, B, C, D & E. Copyright © 1993. IEEE. All rights reserved.
Bulletin 1724E-300

Page 398

Accuracy classes are based on the requirement that the transformer correction factor shall be within

specified limits when the power factor of the metered load has any value from 0.6 lag to 1.0, from zero

burden to the specified standard burden and at any voltage from 90 to 110 percent of the rated transformer

voltage. Accuracy classes and corresponding limits of TCF are shown in Table 5-68.

5.10.7.2.3 The thermal burden rating of a voltage transformer shall be specified in terms of the

maximum burden that the transformer can carry at rated secondary voltage without exceeding the

temperature rise above 30°C (86°F) ambient permitted by Table 5-67.

5.10.7.3 Application Data: The following information has to be obtained from the manufacturer to

accurately determine operating characteristics and limits:

• Typical ratio and phase angle curves for rated primary voltage, plotted for the standard

burdens and for the same numerical burdens with unity power factor, from zero burden to the

maximum standard burden volt-amperes of the transformer

• Accuracy ratings for all standard burdens up to and including the maximum standard burden

rating of the transformer

• Thermal burden rating

5.10.8 Combination Units

5.10.8.1 Combined Instrument Transformers: Combined instrument transformers, sometimes

called metering units, include a voltage transformer and current transformer in a single free-standing unit.

These units are used primarily in metering applications where a dedicated voltage transformer and current

transformer are used for revenue metering.

Each instrument transformer in the combined instrument transformer has to meet the requirements and

ratings of ANSI/IEEE Std. C57.13 for the application. Ratings are provided for each instrument

transformer in the combined unit.

These units have the advantage of cost savings by eliminating a set of support structures and foundations

and reducing substation space requirements. A disadvantage of the combined instrument transformers is

a failure of one component requires the entire unit to be removed from service and repaired or replaced.

5.10.8.2 Power Voltage Transformers: Another type of combination unit called a power voltage

transformer combines an auxiliary power transformer with instrument voltage transformers.

A common primary winding is included with multiple secondary windings in a single free-standing unit.

One or more of the secondary windings are rated for power application, typically 10 kVA to 100 kVA.

Additional secondary windings are also included and can be rated either metering or relay accuracy

classes with standard burdens as given in Table 5-78.

The advantage of these devices is cost saving by eliminating a set of support structures and reducing

space requirements. The devices are also useful at remote switching stations or high-voltage substations

where no local distribution service is available for station service. One disadvantage of the power voltage

transformer is the loss of accuracy in the metering or relaying secondary windings when the power

secondary winding is loaded. Consult the manufacturer to determine the effects of power winding load

on the performance of the voltage transformer.
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5.10.9 Tests

5.10.9.1 Routing Tests: Paragraph 4.7.2 of ANSI/IEEE Std. C57.13 lists the minimum routine tests

an instrument transformer receives at the factory to ensure the instrument transformer meets the specified

requirements. The routine tests include applied potential dielectric tests, induced potential tests, accuracy

tests, and polarity checks. Additional tests are performed by the manufacturer for each transformer

design (type tests) and are not performed on every transformer. These tests are listed in ANSI/IEEE

Std. C57.13, Paragraph 4.7.3.

5.10.9.2 Test Procedures: Section 8 of ANSI/IEEE Std. C57.13 describes the methods recommended

for testing an instrument transformer. Although most of these tests are usually performed only in the

factory, there may be occasions when the user will perform some of them in the user’s own testing facility

or in the field. It is recommended that Section 8 be consulted for guidance and precautions whenever

such tests are planned.

5.10.10 References

ANSI Std. C37.04, “Rating Structure for AC High-Voltage Circuit Breakers Rated on a Symmetrical

Current Basis.”

ANSI Std. C37.06, “Rating Structure for AC High-Voltage Circuit Breakers Rated on a Symmetrical

Current Basis—Preferred Ratings and Related Required Capabilities.”

ANSI Std. C37.20, “Switchgear Assemblies Including Metal-Enclosed Bus.”

ANSI/IEEE Std. C57.13, “Standard Requirements for Instrument Transformers.”

ANSI/IEEE Std. C57.13.1, “Guide for Field Testing of Relaying Current Transformers.”

ANSI/IEEE Std. C57.13.2, “Conformance Test Procedures for Instrument Transformers.”

ANSI/IEEE Std. C57.13.3, “Guide for the Grounding of Instrument Transformer Secondary Circuits and

Cases.”

IEEE Std. 37.09, “Standard Test Procedure for AC High-Voltage Circuit Breakers Rated on a

Symmetrical Current Basis.”

IEEE Std. C57.12.00, “IEEE Standard General Requirements for Liquid-Immersed Distribution, Power,

and Regulating Transformers.”

NEMA Std. SG 5, “Power Switchgear Assemblies.”
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5.11 COUPLING CAPACITORS AND COUPLING CAPACITOR VOLTAGE

TRANSFORMERS

5.11.1 General

Both coupling capacitors and coupling capacitor voltage transformers are single-phase devices that utilize

one or more capacitor units, usually mounted on a base, to couple a communication signal to a highvoltage power line.

Coupling capacitors (CCs) are used in conjunction with line traps and line tuners for power line carrier

(PLC) communication over high-voltage power lines. A CC with an electromagnetic unit is called a

Coupling Capacitor Voltage Transformer (CCVT). CCVTs can be used to supply voltage for metering

and protection applications similar to a voltage transformer.

The ANSI Standard applicable to the power line coupling capacitors is ANSI Std. C93.1, “Power Line

Coupling Capacitors and Coupling Capacitor Voltage Transformers (CCVT) Requirements.” This

standard covers such items as definitions, service conditions, ratings, testing, and manufacturing

requirements.

5.11.2 Coupling Capacitors

Coupling capacitors are primarily used for coupling power line carrier communication equipment to a

high-voltage power line. A coupling capacitor used for power line carrier coupling is shown

schematically in Figure 5-58. As indicated in Figure 5-58, a coupling capacitor will usually consist of the

following equipment and accessories.

Figure 5-58: Coupling Capacitor with Carrier Accessories. Ref. ANSI Std. C93.1-1990, Figure A1.
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5.11.2.1 Capacitor Stack: An assembly of one or more capacitor units. The capacitor units are

enclosed in an oil-filled, sealed porcelain shell and typically mounted on a supporting base.

5.11.2.2 Base: A supporting enclosure beneath the capacitor stack that may include accessories for

functional or protective purposes.

5.11.2.3 Drain Coil: An inductor connected between the low-voltage terminal and the ground

terminal to provide low impedance to the 60 Hz frequency current and high impedance to the carrier

frequency current.

5.11.2.4 Carrier Grounding Switch: The grounding switch is connected across the low-voltage and

ground terminals and is used to bypass the drain coil during inspection or maintenance. It is operated

externally by hook stick from ground elevation. It does not interrupt the operation of the high-voltage

line or, when used, the voltage transformer components; however, closing the carrier grounding switch

may affect the accuracy of the voltage transformer components.

5.11.2.5 Protective Gap: Spaced electrodes connected between the low-voltage and ground terminals

for limiting transient overvoltages.

5.11.2.6 Lead-in Terminal: The terminal to which the coaxial cable from the power line carrier line

tuning equipment is connected.

5.11.2.7 High-Voltage Terminal or Line Terminal: The terminal connected to the high-voltage

power line. This terminal may also be connected on the line side of a line tram. Fusing of the highvoltage terminal is not necessary.

5.11.2.8 Low-Voltage Terminal: The terminal at the lower end of the capacitor stack located within

the base.

5.11.2.9 Ground Terminal: The terminal on the exterior of the base connected directly to the ground

grid.

5.11.2.10 Space Heater: A space heater may be provided in the base for prevention of condensation.

5.11.2.11 Space for Future Voltage Transformer Components: Provisions may be supplied for

installing the electromagnetic unit for future conversion to a CCVT.

5.11.3 Coupling Capacitor Voltage Transformers

Coupling capacitor voltage transformers, commonly termed capacitor voltage transformers (CVTs), are

devices used for coupling to a power line to provide low voltage(s) for the operation of relays and

metering instruments. Power line carrier accessories or provisions for future installation of carrier

accessories may be included in the base.

Coupling capacitor voltage transformers are commonly supplied without carrier accessories, especially at

voltages above 115 kV, as a more economical alternative to inductive voltage transformers. Coupling

capacitor voltage transformers can be provided with the same ratings and accuracy as inductive voltage

transformers.
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However, because of the energy-storage capability of capacitors, sudden reductions in the power line

voltage may result in momentary distortion of the CCVT secondary voltage. The amount of distortion is

related to CCVT capacitance and the burden (secondary load) value and configuration. Modern CCVT

designs are available to minimize this problem.

A schematic representation of a typical CCVT with carrier coupling accessories is shown in Figure 5-59.

In addition to the carrier coupling accessories described above for a coupling capacitor, a CCVT may

include the following equipment and accessories.

Figure 5-59: Typical Coupling Capacitor Voltage Transformer with Carrier Coupling Accessories.

Ref. ANSI Std. C93.1-1990, Figure A2.
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5.11.3.1 Capacitor Divider: In the capacitor stack, the units are divided to form two capacitances

connected in series (C1 and C2). The point between the two capacitances is tapped to provide a voltage

proportional to the power line voltage. The tapped connection is brought to a terminal in the base

designated as the intermediate-voltage terminal. The electromagnetic unit is connected between the

intermediate-voltage terminal and the ground terminal.

5.11.3.2 Transformer: The transformer is the portion of the electromagnetic unit that provides a

reproduction of the power line voltage at the secondary terminals of the transformer. Transformers

commonly have two or more secondary windings. Each secondary winding is typically rated 120 volts

line-to-neutral with a tap rated 69.3 volts line-to-neutral.

5.11.3.3 Secondary Terminals: The secondary terminals of the voltage transformer are connected

for metering, protection, and control functions. The secondary circuits are typically fused although a

common practice is to not fuse critical protection circuits when reliability is the key consideration. Some

manufactures provide CCVTs that are designed to withstand a secondary short circuit continuously and

do not require fusing; however, never intentionally short circuit the secondary of any CCVT. Also, the

secondary windings of CCVTs should not be connected in a closed delta because excessive current may

circulate in the delta.

5.11.3.4 Choke Coil or Blocking Impedance: The transformer is connected to the intermediatevoltage terminal through the choke coil or carrier blocking impedance. The choke coil prevents carrier

frequencies from entering the electromagnetic unit. A protective gap is provided across the choke coil to

limit voltage surges.

5.11.3.5 Series Reactor: A series reactor may be included in the electromagnetic unit to increase the

inductive reactance of the electromagnetic unit to approximately equal the capacitive reactance of the

CCVT at the power frequency.

5.11.3.6 Potential Grounding Switch: The potential grounding switch is connected between the

capacitor divider intermediate-voltage terminal and the ground terminal. When closed, the potential

grounding switch removes the electromagnetic unit from service. Closing the switch does not interrupt

the operation of the high-voltage line or the carrier equipment. Like the carrier grounding switch, the

potential grounding switch is located externally on the base and operated from elevation by hook stick.

5.11.3.7 Transformer Overvoltage Protection: Protective gaps or other means are provided to limit

overvoltages in the transformer.

Older CCVTs may contain additional accessories for adjusting the voltage and capacitance of the unit.

These accessories may be located in a separate cabinet mounted close to the base, usually on the same

supporting structure. The accessories were required because, as the capacitors age, the voltage and

capacitance values of the CCVT drift and require periodic calibration. Modern CCVT designs and

materials have eliminated the need for these adjustments.

Different manufactures may use different components and arrangements to obtain secondary voltages

representative of the power line voltage at the required accuracy. Manufacturers may also be able to

provide specialty CCVTs for unusual applications.
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Figure 5-60 shows several CCVTs installed in substations with and without wave traps. Consult with

manufacturers for the options available for installation of wave traps with coupling capacitors and

CCVTs.

5.11.4 Service Conditions

ANSI Std. C93.1 defines the usual service conditions for which CC and CCVT manufacturers are

required to design their equipment. Consult the manufacturer when service conditions are unusual or

exceed the limits stated below.

5.11.4.1 Temperature: Coupling capacitors and CCVTs are designed for outdoor service at ambient

temperatures from –40°C to +45°C (–40°F to +113°F). The maximum mean temperature for a one-hour

period is +45°C. Other limits are +40°C mean over 24 hours and +30°C mean over one year.

5.11.4.2 Altitude: Maximum altitude is 1000 meters (3300 feet). Dielectric strength is decreased at

higher altitudes approximately 5 percent for each 500 meters above 1000 meters.

5.11.4.3 Frequencies: The power frequency is 60 Hz. The carrier frequency range is 30 to 500 kHz.

5.11.4.4 Unusual Service Condition: The service condition is considered unusual if the equipment

will be exposed to damaging or explosive fumes; excessive, abrasive, or explosive dust; steam; or salt

spray. Applications that require special consideration by the manufacturer include use in high-voltage

power cable systems and gas-insulated substations.

5.11.5 Ratings

5.11.5.1 Voltage: The standard voltage ratings and associated insulation levels for CCs and CCVTs

are provided in Table 5-79. Table 5-79 includes system voltage ratings, insulation withstand voltage

levels for impulse and switching surges, power frequency withstand voltages, and minimum leakage

distance of the capacitor porcelain. The right-hand columns show the standard performance reference

voltage and marked ratios for CCVTs.

Table 5-79 shows that standard CCs and CCVTs are rated for line-to-ground service and possess full

BILs for each nominal system voltage level. The full BIL is used partly due to standardization but also in

recognition of the fact that these devices are usually located at line terminations and thus are more

exposed to incoming power line surges.
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Figure 5-60: Coupling Capacitor Voltage Transformers With and Without Wave Trap.

Courtesy of Haefely Trench, Scarborough, Ontario, Canada.
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Table 5-79: Voltage Ratings, Dielectric Strengths, Leakage Distances, and Marked Ratios

for CCs and CCVTs.

Ref. ANSI Std. C93.1-1990, Table 3. Reproduced with permission of the

National Electrical Manufacturers Association.

CCVT

Nominal

System

Voltage

Maximum

System

Voltage

Maximum

Rated

Volatge

Minimum

Power-Frequency

Withstand Voltage

Minimum

Basic

Impulse Insulation

Minimum

Basic Switching

Impulse Insulation

Minimum

Leakage

Performance

Reference

Voltage

Marked

Ratio

(Note 4)

(Note 1) (Note 2) (Note 3) (kV) Level (BIL) Level (BSL) Distance (Note 4) Lower Higher

(kV) (kV) (kV) 1 Minute Dry 10 Second Wet (kV) (kV) (inches(mm)) (Volts) Ratio Ratio

Col 1 Col 2 Col 3 Col 4 Col 5 Col 6 Col 7 Col 8 Col 9 Col 10 Col 11

34.5 36.2 21 85 72 200 -- 26 (660) 20125 175:1 300:1

46 48.3 28 110 95 250 -- 35 (890) 27600 240:1 400:1

69 72.5 42 165 140 350 -- 48 (1220) 40250 350:1 600:1

115 121 70 265 230 550 -- 79 (2010) 69000 600:1 1000:1

138 145 84 320 275 650 -- 92 (2340) 80500 700:1 1200:1

161 169 98 370 325 750 -- 114 (2900) 92000 800:1 1400:1

230 242 140 525 460 1050 -- 154 (3910) 138000 1200:1 2000:1

345 362 209 785 680 1550 975 230 (5840) 207000 1800:1 3000:1

500 550 318 900 780 1800 1300 350 (8890) 287500 2500:1 4500:1

765 800 462 1200 1050 2425 1675 510 (12950) 431250 3750:1 6250:1

NOTES:

(1) Values from 34.5 kV through 230 kV correspond to the preferred nominal system voltages given in ANSI C84.1-1989, and values from

345 kV through 765 kV to typical “nominal” voltages given in ANSI C92.2-1987.

(2) Values from 36.2 kV through 242 kV correspond to the maximum voltage of the tolerable zone for voltages at substations and on

transmission systems given in ANSI C84.1-1989, and values from 362 kV through 800 kV to the preferred maximum system voltages

given in ANSI C92.2-1987.

(3) These values are phase-to-ground voltage corresponding to maximum system voltages divided by 3 .

(4) For CCVTs in this table that have a double ratio achieved by means of a tap in the secondary winding(s), the nonpolarity end of the

winding shall be the common terminal. Application of performance reference voltage between the high-voltage terminal and the ground

terminal will result in 115 volts across the secondary windings having the lower ratio.
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5.11.5.2 Thermal: The thermal burden rating of a CCVT is expressed in terms of the maximum

burden a CCVT can supply at maximum voltage without exceeding the temperature limitations of the

CCVT. The burden, expressed in volt-amperes, is given for each secondary winding. For CCVTs with

multiple secondary windings, a total thermal burden (primary winding thermal burden) is also provided.

If a single thermal rating is provided, it is applicable to any distribution of secondary volt-amperes.

5.11.5.3 Accuracy: Accuracy ratings are a means of expressing the conformity of the values obtained

at the CCVT secondaries to the values calculated using the marked ratios. Accuracy classes have been

established that define accuracy limits, in terms of ratio correction factor (RCF) and phase angle. The

RCF is the ratio of the true ratio to the marked ratio. Standard accuracy classes include 0.3, 0.6, and 1.2

classes.

Each secondary winding is assigned an accuracy class for the standard burden for which it was designed.

Burdens for accuracy rating are expressed in volt-amperes at a specified lagging power factor and given a

letter designation, as shown in Table 5-80. These values are applicable at either 120 or 69.3 volts.

Table 5-80: Burdens for Accuracy Rating.

Ref. ANSI Std. C93.1-1990, Table 5. Reproduced with permission of the

National Electrical Manufacturers Association.

Burdens*

Characteristics on

120-Volt Basis

Characteristics on

69.3-Volt Basis

DesignationVoltAmperesPower

Factor

Resistance

(ohms)

Inductance

(henries)

Impedance

(ohms)

Resistance

(ohms)

Inductance

(henries)

Impedance

(ohms)

M 35 0.20 82.3 1.07 411 27.4 0.356 137

W 12.5 0.10 115.2 3.04 1152 38.4 1.01 384

X 25 0.70 403.2 1.09 576 134.4 0.364 192

Y 75 0.85 163.2 0.268 192 54.4 0.0894 64

Z 200 0.85 61.2 0.101 72 20.4 0.0335 24

ZZ 400 0.85 30.6 0.0503 36 10.2 0.0168 12

* The burden designations have no significance at frequencies other than 60 Hz.

The accuracy rating of the typical CCVT will usually apply to the total burden on the device regardless of

how that burden is divided among the secondary windings, provided that any burden limit on any winding

is not exceeded.

CCVTs are classified for either relaying service or metering service. Metering service CCVTs has to

maintain the stated accuracy for primary voltages between 90 percent of the performance reference

voltage and maximum rated voltage. Metering service CCVTs shall be assigned an accuracy class of 0.3,

0.6, or 1.2 for each winding.

Relaying service CCVTs are always assigned an accuracy class of 1.2R. Relaying service CCVTs have

additional requirements for maintaining accuracy limits under varying frequency conditions and lowvoltage conditions.

5.11.5.4 Capacitance: CCs and CCVTs are usually classified as “high capacitance” or “extra-high

capacitance,” depending on the value of the high-voltage capacitance. The high-voltage capacitance C1 is

the capacitance between the high-voltage and intermediate-voltage terminals. Available ratings are listed

in manufacturers’ catalogs.

The typical “high-capacitance” unit can be equipped for broadband carrier coupling, and some units can

be furnished for one- or two-frequency carrier coupling. High-capacitance CCVTs can be supplied with
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an accuracy class of 0.3, 0.6, or 1.2. Burden capability ranges up to 200 VA. They are not suitable for

revenue metering, but can be used for relaying and SCADA systems.

The typical “extra-high capacitance” device is particularly applicable on the higher voltage systems,

115 kV and above, where the increased capacitance rating is desired to provide a low impedance path for

carrier signals. It is also the only type of CCVT suitable for revenue metering, when specified with an

accuracy class of 0.3. Burden capability ranges up to 400 VA.

The higher capacitance devices are generally more expensive than the lower capacitance devices.

However, capacitance can usually be equated to performance. In general, the higher the capacitance of

the device, the better its performance characteristics will be.

The “extra-high capacitance” CCVT is particularly applicable at high-voltage and extra-high-voltage

interconnections between two utilities where revenue metering from the primary transmission line is

essential and where broadband coupling is desired between carrier transmitter–receiver equipment and the

power line.

5.11.6 Tests

Section 6 of ANSI Std. C93.1 fully describes the various test conditions, routine tests, and design tests

performed on CCs and CCVTs.

Two routine production tests that are to be made on each completed capacitor unit (i.e., an assembly of

capacitor elements in a single container with accessible connections) are as follows:

5.11.6.1 Capacitance and Dissipation Factor Measurements: Capacitance and dissipation factor

measurements up to rated maximum voltage and frequency before and after dielectric tests.

Dissipation factor is the tangent of the angle delta by which the phase difference between the voltage

applied to the capacitor and resulting current deviates from 90 degrees. The dissipation factor is usually

expressed as a percentage.

5.11.6.2 Dielectric Tests: Every capacitor is subjected to a power-frequency withstand voltage test,

applied between the high-voltage and ground terminals in accordance with the values shown in

Table 5-79, column 4.

Other routine tests include verification of the protective gap sparkover settings, accuracy, and polarity.

For accuracy tests, ratio and phase angle measurements are made at the performance reference voltage

and power frequency at the maximum burden for each rated accuracy class and at zero burden.

When testing a CCVT or during operation, never energize the CCVT from the secondary winding. The

CCVT may be damaged by the voltages and currents that develop in the CCVT.

5.11.7 References

ANSI Std. C93.1, “Power Line Carrier Coupling Capacitors and Coupling Capacitor Voltage

Transformers (CCVT) Requirements.”
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5.12 MOBILE UNITS

A mobile unit substation or mobile transformer is one in which all the components are mounted on a

highway trailer or railcar. These units may be readily moved from one location to another by a tractor or

locomotive. Mobile units are used to provide supplementary service during seasonal and temporary load

conditions and as spares for existing installations during periods of outage due to equipment breakdowns

or planned maintenance and construction. Their use can permit a higher quality of maintenance, more

safely and at less cost, and reduce system investment in overall transformer capacity.

The actual makeup of a mobile unit will depend on factors such as the intended scope of application,

degree of flexibility and reliability desired, physical size and weight restrictions, safety, and economics.

Each user will have to determine the correct blend of these factors for his system.

5.12.1 Feasibility

The purchase of a mobile unit should be supported by an economic study proving this method of

providing service continuity to be less expensive than other methods (such as individual spare

transformers or looped feeder lines) that can provide comparable reliability of service.

The study should consider carefully the kVA capacity and voltages of the substation transformers to be

spared by the mobile unit. There is a practical limit to the flexibility that should be attempted in one unit.

Two (or more) units may be the best answer on some systems where the variety of substations is great.

The design of many mobile units is restricted by the opposing requirements of larger transformer

capacity, higher primary voltages, and highway limitations on physical size and weight. Although it is

generally desirable to obtain the maximum capacity from the transformer section of a mobile unit, it is the

transformer kVA that has to be limited in most cases since, for a given mobile unit, the other components

tend to remain the same in size and weight, regardless of kVA.

Since highway restrictions vary from state to state, it is difficult for a manufacturer to adopt a standard

design for a mobile unit. Therefore, close coordination should be exercised among the purchaser, the

design engineers, and the state highway commissions.

In attempting to meet all the requirements desired, it is important that all necessary safety clearances

between phases and phase-to-ground be maintained in accordance with Chapter 4. Basic insulation levels

and surge protection should be selected and coordinated in accordance with good modern practice and the

specific system where the mobile unit will be used (see Section 5.2, Power Transformers, and Section 5.8,

Surge Arresters).

5.12.2 Mobile Transformers

This is a transformer, usually three-phase, mounted on a trailer or semi-trailer together with cooling

equipment such as an oil pump, heat exchanger, fans, etc. It is intended for application in a substation as

a spare transformer in place of permanently installed transformers that may have failed or that may be

undergoing maintenance. Other uses include provision of extra kVA capacity during temporary heavy

load situations.

Switchgear, circuit breakers, or reclosers may or may not be included. It is recommended, however, that

both high- and low-voltage surge arresters be mounted either on the transformer or on the trailer since the

transformer, when in use, may be too far from the substation arresters to be protected adequately.
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The availability of a mobile three-phase transformer as a spare permits a saving in the purchase of

substation transformers. Instead of buying four single-phase transformers in order to have a spare in each

substation, a power system can save a substantial part of this cost by buying one three-phase transformer

and depending on the mobile unit for a spare. Because of the much higher cost of the mobile unit, this

saving can be realized only if the system operates several substations having approximately the same

kVA size and compatible voltage requirements.

5.12.3 Mobile Substations

A mobile substation may include, in addition to the transformer, air switches, surge arresters, high-voltage

fuses, reclosers or breakers, voltage regulating equipment, control power and instrument transformers,

meters and relays, and a control cabinet and various accessories to permit it to operate as a complete

substation independent of any permanent ground-mounted equipment. Thus, it can be used not only as a

spare transformer but can replace an entire substation that has been damaged or can serve as a temporary

substation in a new location until a permanent substation can be built.

One limitation of a mobile substation is the number of outgoing distribution circuits that can be provided

conveniently. Mobile substations can generally provide only one or two distribution circuits without an

auxiliary switching structure or other supplementary equipment mounted on a separate trailer.

5.12.4 Phase Rotation Indicators

Three-phase units should be equipped with suitable phase rotation indicators or relays to ensure that

power supplied to distribution circuits has the same phase rotation as that supplied from the permanent

substation. Relays should also be provided to prevent reverse rotation of the fan and pump motors.

Reversing switches should be added to these motors so that they can adapt to the phase rotation of the

power supply.

5.12.5 Other Considerations

5.12.5.1 Impedance: To reduce size and weight, the transformers in mobile units are usually

designed for forced-cooled operation with higher impedances based on the forced-cooled kVA rating than

are normal for most self-cooled power transformers. These impedances sometimes are as high as 12 to

15 percent. This usually makes it impractical to continuously operate a mobile unit in parallel with a

ground-mounted unit unless a sacrifice in total kVA available from the paralleled units is acceptable.

A general rule is that, for proper division of load, the impedances of transformers connected in parallel

should be as close as possible and in no case differ by more than 7.5 percent. (For example, consider a

transformer with a nameplate impedance of 7 percent. The allowable variation of impedance in a

paralleled unit is 7.5 percent of the nameplate impedance or 0.525 percent. The paralleled transformer,

therefore, should have an impedance between 6.475 percent and 7.525 percent.) If this limitation is not

observed, the transformers will not divide the load proportionately, so the transformer having the lower

impedance (on a common base) may be seriously overloaded. The higher characteristic impedance of

mobile units on a forced-cooled base also causes a greater voltage drop under load and places a heavier

duty on voltage regulating equipment.

Temporarily paralleling the mobile unit with the ground-mounted unit should be acceptable.

Consideration should be given to the risk involved due to increased short-circuit levels. Equipment

ratings should be checked to ensure safe operation.
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5.12.5.2 Cooling System: Mobile units customarily use a forced oil–forced air cooling system that is

more complex than the self-cooled system common in permanent substations.

CAUTION: Before this additional fan and pump load is placed on the substation station power system,

its capacity should be carefully checked. Several features are desirable in the cooling system to reduce

operating difficulties and to facilitate maintenance and repair:

5.12.5.2.1 Valves: Valves should be installed in the oil piping between the heat exchanger and the

transformer tank. These allow maintenance of the forced oil cooling equipment without drawing down oil

in the transformer tank.

5.12.5.2.2 Relay: A flow-type relay should be installed in the forced oil system to sound an alarm or

trip the breaker if oil circulation is blocked. If oil circulation or cooling is lost, a mobile unit has no loadcarrying capability and it can remain energized only for a few hours without load before excessive

overheating would occur.

Fan and pump motors should have individual disconnecting switches to expedite fault location.

5.12.5.2.3 Oil Piping: The oil piping should preferably have welded joints and flange connections.

Threaded connections are not recommended for mobile units because of possible loosening during

transport.

5.12.5.3 Primary and Secondary Connections: Connections from mobile units to permanent

substations or to overhead lines should be as short as possible. Insulated cables of the shielded type may

be used where connections are quite long or exposed enough so that bare conductors may be a hazard.

Cables should be equipped with suitable terminations (stress cones, potheads) at each end. Because of the

expense of higher voltage (69 kV and above) cable and terminations, it is especially desirable that the

primary connections be short so that bare vertical jumpers can be used safely. The ease with which

connections can be made is a major factor in determining the speed with which a mobile unit may be put

into service. It may be desirable to store at the substation any large pieces of equipment required to

complete the installation, such as temporary wood poles, insulators, etc.

5.12.5.4 Alarm Connections: The mobile unit’s alarm circuits should be temporarily connected to

the substation alarm bus. Alarm indications should be considered for such items as hot oil temperature,

low oil level, high combustible gas content, breaker lockout, security gate open or unlocked, and any

other important indications of abnormal conditions.

5.12.5.5 Safety Considerations: A mobile unit has to always be considered as live and dangerous

when in an operating position. Great care should be exercised in grounding the trailer and neutrals.

Effective barriers around and under live parts should be provided wherever necessary. Interlocks should

be considered to prevent energizing the unit if any required barriers are not properly in place.

Additionally, a fence should be constructed around the entire mobile unit unless its operating position lies

inside the substation’s security fence.

Because of the different application of mobile units as compared to regular substation components, it is

often acceptable to consider the mobile unit as a tool that is to some extent expendable. This approach

will permit reasonable deviation from strict application of many major, basic electrical properties.
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Reduced insulation levels, higher temperature ratings, higher impedance, more extreme overloading (into

the loss-of-life range), and reduced clearances can all be considered as possible tradeoffs to obtain more

transformer kVA capacity and voltage selection flexibility. Other optimal application considerations may

be found through discussions with suppliers of mobile units. As mentioned earlier, minimum safety

requirements should not be sacrificed to obtain other advantages.

5.12.5.6 Protection: In designing the protection for a mobile unit, consideration should be given to

two factors that distinguish it from the normal substation situation:

1. A mobile unit is much more expensive.

2. The temporary nature and perhaps hurried installation may increase the probability of a fault.

Both factors may dictate a better than normal protection scheme.

5.12.5.7 Installation Requirements of Mobile Units: Chapter 4, Physical Layout, discusses many of

the considerations for installation of mobile units at the substation.

5.12.6 Accessories Included with the Mobile Unit

All accessories necessary for proper operation of the mobile unit should be placed at convenient locations

on the trailer. Accessories that are readily available at the locations where the unit is expected to be used

may be omitted. Determining which accessories to mount on board will require a careful study of all sites

as well as space availability on the trailer.

Types of accessories to be considered include power cable and connectors, grounding cables and

connectors, power supply transformers, control batteries, heaters, lights, plug outlets, spare fuses, fencing,

and special equipment or tools for mobile unit components and the trailer.
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CHAPTER 6

SITE DESIGN

6.1 GENERAL

The objective of site work design for a substation yard is to provide an easily accessible, dry,

maintenance-free area for the installation and operation of electrical substation equipment and structures.

Factors related to the actual location of the substation site are covered in Chapter 2.

The engineer should make a personal site inspection before the design is started. The engineer should

take advantage of the natural drainage and topographical features in the design consistent with the

electrical layout since coordination of the two is essential.

6.2 TYPES OF GRADED YARDS

There are generally three basic profiles for substation yards:

1. Flat—most prevalent (Figure 6-l)

2. Sloped—occasionally required (Figure 6-2)

3. Stepped—seldom required (Figure 6-3)

Figure 6-1: Flat Yard

Figure 6-2: Sloped Yard on Moderately Sloped Site
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Figure 6-3: Stepped Yard

6.2.1 Flat Yards

The basic flat yard is more desirable for the layout and operational function of a substation. It permits

uniformity in foundation elevations and structure heights. Unless there are property restrictions, severe

topographical features, subterranean rock, or other considerations dictate otherwise, the yard should be

graded nominally flat. (See Section 6.4, Drainage Considerations.)

6.2.2 Sloped Yards

Occasionally, property restrictions or economic considerations will outweigh the desirability for a flat

yard, and a continuously sloping yard may be advantageous.

6.2.3 Stepped Yards (Two or More Levels)

Stepped yards are usually created by extreme property restrictions, adverse mountainous terrain, or

underlying rock formations making excavation uneconomical.

Modification of any of the three types may be necessary to arrive at the optimum yard design. Sloped and

stepped sites entail extra design considerations and close coordination with the electrical layout. There

may be more structures required and variable foundation elevations.

6.3 PRELIMINARY REQUIREMENTS

The following lists some of the basic information required for the site preparation design for a substation

yard:

a. Area maps (aerial photos if available)

b. Topographic drawing of immediate area showing:

1. Ground elevations on a grid system at 15m (50-foot) spacing

2. Location and elevation of existing roads, railroads, ditch inverts, and culverts

3. Location of pertinent overhead or underground utilities, particularly the exact location and

depth of any pipelines
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4. Property plan (legal description of property)

5. Location of the area’s drainage exits

6. High water elevation in area, if any

7. Flood zone designation with base flood elevation, if any

c. Soil borings in immediate site area

6.4 DRAINAGE CONSIDERATIONS

6.4.1 Stormwater Management

Review state and local government regulations for stormwater management requirements. Many local

governments have adopted storm drainage criteria and require that stormwater detention or retention

basins be provided, and a few require zero discharge from the site.

6.4.2 Surface Drainage System

Generally all three profiles lend themselves to a surface runoff system. Such a system consists of a gently

sloping (0.5 percent to 0.75 percent) ground surface so that the water drains to the edge of the yard or to

shallow ditches within the yard. The ditches may discharge into culverts or shallow open channels

removing the runoff from the yard.

6.4.3 Closed Drainage System

A closed drainage system is a network of catch basins and storm sewer pipe that provides a more positive

means of yard drainage. This type of system is quite costly. Circumstances other than economics,

however, may require the use of this system. Rural substations will rarely require a closed drainage

system.

6.4.4 Planning

The yard surface drainage has to be coordinated with the location of cable trenches and roads within the

yard. The yard profile (flat, sloped, or stepped) may present varying drainage design considerations.

Careful review of the quantity, quality, and particularly the location of the discharge water from the yard

is emphasized. Planning the initial drainage system for a future substation addition is sometimes

required. Generally a good rule to follow is do not discharge any more water into an existing drainage

area outlet than what originally occurred. Small interceptor ditches strategically located will prevent

erosion of slopes or embankments.

6.4.5 Design

Whenever it is necessary to calculate the amount of rainfall runoff for the design of culverts, storm sewer

pipes, detention or retention ponds, or ditches, a widely used and accepted method is the “Rational

Method.” The Rational Method is not recommended for drainage areas much larger than 100 to 200

acres.

The Rational Method formula is expressed by Equation 6-1:
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Equation 6-1

Q = CiA

Where:

A = Drainage area in m2 (acres)

i = Average rainfall intensity m/hr (in/hr) for the period of maximum rainfall of a storm of a

given frequency of occurrence, having a duration equal to the “time of concentration (tc)”

tc = Time required for runoff from remotest part of drainage area to reach the point under design

C = Runoff coefficient

Q = Quantity m3 /hr (cfs) (NOTE: Metric units have to be converted to m3/s for the ChezyManning Formula.)

Table 6-1 and Figures 6-4 and 6-5 provide information to assist in determining the rainfall intensity for

different geographical areas, durations, and recurrence intervals. Additional information concerning

rainfall and frequency is available from U.S. Weather Bureau Offices and other technical and

hydrological publications. Tables showing runoff coefficients for various types of terrain and gradient are

available in texts on this subject.

Table 6-1: Rainfall Intensity and Conversion Factors

Frequency of storm occurrence should be 2 or 5 years, and the time of concentration should be between

15 and 20 minutes for a reasonable and economical design. The design example illustrates a sample

problem.

6.4.5.1 Design Example

Design a culvert in a substation in Lansing, Michigan, given the following information:

1. Drainage area = 2000 m2

2. Time of concentration = 15 minutes

3. Period of recurrence = 5 years

4. Coefficient of runoff = 0.50
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Figure 6-4: 2 Year 30-Minute Rainfall Intensity (cm/hr).

Adapted from Chart 2, Rainfall Frequency Atlas of the United States,

U.S. Department of Commerce, Weather Bureau, Technical Paper 40, May 1961.

Figure 6-5: 2 Year 30-Minute Rainfall Intensity (inches/hr).

Rainfall Frequency Atlas of the United States,

U.S. Department of Commerce, Weather Bureau, Technical Paper 40, Chart 2, May 1961.
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From Table 6-1 and Figures 6-4 and 6-5 determine i for a 5-year storm of 15 minutes’ duration as

follows:

(2-yr., 30-min. duration) (15-min. duration factor) (5-yr. recurrence factor)

i = 0.05m/hr x 1.44 x 1.3

= 0.094 m/hr

The culvert then has to convey:

Q = 0.50 x 0.094 m/hr x 2000 m2 = 94 m3/hr or

Q = 94 m3/hr x 1 hr/3600 sec = 0.026 m3/sec

Assuming that 0.20m φ, corrugated, metal pipe will handle the flow, and using the Chezy-Manning

Formula, determine the slope of the pipe as follows:

3 2 2 3 1 2

0 05

0 024

1

0 026 sec 0 032 / /x . m x s

.

. m / = . m x

S = 0.021 m/m

0 81

0 032 m

0 026 m sec

2

3

.

.

. /

v = = m/sec

The velocity at the minimum slope to handle the discharge volume is not quite self-cleaning, but would

probably be okay.

Once the quantity of water is determined by the Rational Method, the actual size of storm sewer pipe,

culverts, or ditches may be determined using the Chezy-Manning Formula:

Equation 6-2

x R 3 x S 2 (metric)

n

1.0 Q AV A x

2 1 = =

Equation 6-3

x R 3 x S 2 (English)

n

1.486 Q AV A x 2 1 = =

Where:

Q = Volume of pipe or ditch discharge m3/s (cfs)

A = Cross-sectional area of pipe or ditch flow m2 (ft2)

V = Velocity = m/s (ft/s)

n = Roughness coefficient for pipe or ditch

R = Hydraulic radius of pipe or ditch m (ft)

for pipe

4

D

)

Wetted Perimeter

Area of Section ( =

S = Hydraulic gradient m/m (ft/ft) (slope of pipe or ditch)
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After the size of pipe or ditch is determined, both minimum and maximum flow velocities should be

reviewed. For pipes to be “self-cleaning” a minimum velocity of one m/s (3 ft/s) is required to prevent

silting. Water in ditches, however, should be allowed to flow approximately 0.5m/s (1 or 2 ft/s) in

unprotected ditches and up to a maximum of about l.5m/s (5 ft/s) in sodded channels before erosion

occurs. Special erosion protection at open discharge ends of storm sewers and both ends of culverts

should be made. Flared end sections and riprap or concrete headwalls should be specified to protect these

areas from scour and erosion.

6.5 EARTHWORK CONSIDERATIONS AND DESIGN

The computation of earthwork quantities is usually the first step in establishing the nominal rough grade

elevation of the yard.

Clearing and grubbing of the site is required, and all vegetation should be removed and properly disposed

of. Generally, the topsoil in the substation area is removed and stockpiled for future use in areas requiring

seeding.

CAUTION: When there may be a question of determining what consists of topsoil material, the engineer

should define the limits of topsoil stripping as specifically as possible.

6.5.1 Borrow

When the natural grade of the proposed site is essentially flat, it may be necessary to bring in fill material

(borrow) to improve the drainage condition of the yard. However, the engineer should avoid the use of

borrow in the site design if possible.

The borrow material should consist of a satisfactory soil free from sod, stumps, roots, large rocks, or other

perishable or deleterious matter. It should be capable of forming a stable embankment when compacted

in accordance with the requirements of this section. Acceptable soils for borrow as identified by the

Unified Soil Classification System are GW, GP, GM, GC, SW, SP, SM, and SC (see Table 6-2).

The borrow pit should be located on the property if possible. If the borrow pit is located a remote

distance from the site, the engineer should reevaluate the site design to avoid hauling borrow long

distances.

6.5.2 Topsoil

Removing topsoil on flat natural sites increases the borrow or fill requirements. Conditions when it

would be excessively uneconomical to remove all the topsoil might be:

a. Excessive depth of topsoil - 0.5 m (18") and deeper

b. When borrow material has to be hauled long distances

The engineer should evaluate alternatives to stripping the topsoil in such circumstances.

One alternative when conditions do not seem favorable for removing topsoil is to uniformly mix the

topsoil with the underlying soil. The mixture is very often suitable for embankments up to 1 meter

(3 feet).
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Table 6-2: Unified (ASTM) Soil Classification System. Ref. ASTM Std. D-2487, Table, Soil Classification Chart,

Figure 3, Plasticity Chart. Copyright © ASTM. Reprinted with permission.
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The mixture may also be compacted in place and serve as a non-bearing base upon which to build the

embankment. The engineer should make certain that the soil to be mixed with the topsoil is

predominantly granular soil. Silts or clays would not be suitable. The mixture should consist of one or

more parts of good soil to one part of topsoil.

When alternatives to topsoil removal are considered, the foundation design should take into account the

depth at which the soil conditions have been altered.

6.5.3 Cut and Fill

On other than flat natural grade conditions, the nominal elevation of the yard is usually determined from a

balance between the required earth “fill” for the embankment and the available earth that has to be

excavated or “cut” from the higher areas of the site. All cut-and-fill slopes should be one vertical to four

horizontal if possible.

There are several software programs available with which the engineer can input digitized topography and

roadway templates and the programs will output earthwork quantities.

The computer software programs contain a digital terrain model (DTM), which is a graphical

representation of the topography of the site. The DTM is created from using a triangulated irregular

network (TIN) model of points from the site survey. Changing the surface terrain is simulated by

building new surfaces to create the final grade and merging them with the existing terrain into the revised

site representation. The software program then compares the two surfaces to compute the earthwork

volumes.

Cut and fill quantities can also be computed by the “average end area method,” which is explained in

most surveying books. Briefly, the method consists of drawing cross sections taken every 15 meters

(50 feet) or 30 meters (100 feet). The areas of cut and fill are determined from the computed sections

with a planimeter. The sections are usually drawn with a vertical scale exaggeration of ten times the

horizontal scale. The sections show both the existing profile and the proposed profile.

To compute the earthwork, the “cut” and “fill” areas of each section are totaled separately and added to

the “cut” and “fill” quantities of the adjacent section.

The average of the cut summation and the average of the fill summation for each pair of adjacent sections

are multiplied by the distance between sections to obtain the volumes of cut and fill. This procedure is

followed at each section plotted across the substation yard.

Usually several adjustments to the proposed elevation are necessary to balance the earthwork. Only 80 to

85 percent of cut volume, as previously computed, is assumed to be available for fill. The 15 to

20 percent reduction allows for losses due to compaction, spillage, and unsuitable material.

6.5.4 Compaction

Adequate compaction during placement of the fill is necessary to develop the required soil bearing

capacity and lateral resistance for the foundation design. It is necessary also to prevent settlement due to

consolidation of the embankment, which may result in ponding, broken ducts, conduits, cable trenches,

etc. All fill areas should be compacted in 200 mm (8-inch) layers to 95 percent of the maximum density

obtained by AASHTO Std. T180. The base upon which the embankment is constructed should also be

loosened and compacted.
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6.5.5 Cleanup

Upon completion of the site work, all excavated earth not used in backfilling should be leveled off or

shaped to present a neat appearance and not obstruct any drainage. Borrow pits should be graded to a

smoothly contoured shape. It may be necessary to provide seeding mulching to such areas.

6.6 ROADS AND OTHER ACCESS

6.6.1 General Access Roads

Access roads into substation yards have to be adequate to sustain heavy equipment under all weather

conditions. Long access roads require design considerations similar to most secondary county or state

roads. Any culverts or sewer crossings also need to be designed for anticipated heavy equipment loads.

6.6.2 Grade

The maximum grade on the access road should generally not exceed 7 percent so that heavy transformers

may be transported to and from the yard by normal movers without problems. Ten percent grades may be

tolerated for short distances of 60 to l00 meters (200 to 300 feet).

6.6.3 Curvature

The inside radius of the access road at 90 degree intersections with major roads should not be less than

15 meters (50 feet) in order to provide sufficient turning space for long vehicles. Smaller radii may be

adequate for substations below 230 kV.

6.6.4 Design

Where space allows, access roads should be about 6 meters (20 feet) wide. The road should be crowned

at the center for drainage.

The subgrade for the road should be prepared and compacted to the same requirements as the

embankment for the yard.

The wearing course for access roads in substations up to 69 kV may consist of a 200 mm (8-inch) deep

aggregate base course. State highway department standard specifications usually contain several different

types of base course material.

For larger substations, the access road may consist of a 200 mm (8-inch) aggregate base course and a

100 mm (4-inch) aggregate surface course. Highway standard specifications include several types and

specify the related material and gradation requirements for the base and surface course material.

Application of the wearing courses should be made in accordance with highway standard specifications.

6.6.5 Railroad Spur

Railroad spurs may be economically feasible at some substation locations. Coordination with the

responsible railroad company will usually determine the requirements for making the turnout. Often the

railroad company will insist on installing the track for a specified length from the main line. Normally,
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the railroad company’s standards are specified in regard to ballast, ties, rails, and connections. The

compaction requirements used for the yard embankment are adequate for the spur track subgrade.

6.6.6 Roadways in the Substation Yard

Many substations do not have any specific drives or roads within the fenced yard. The entire yard is

considered as driveable by light traffic.

If it is desirable to have specific drives within the fenced yard for access to transformer banks or as a

perimeter drive, the wearing surface can be the same as for the access road. The width may be reduced to

5 meters (16 feet) or even less. Inside radii for interior drives may be 7.5 meters (25 feet) or less as space

allows. Culverts and cable trenches should also be designed for anticipated heavy equipment loads.

6.7 EROSION PROTECTION

6.7.1 General

All cut and fill slopes, ditches, and all other areas outside the fenced yard from which topsoil or

vegetation was removed should be protected from wind and water erosion.

In most cases the placement of topsoil, fertilizer, mulch, and seed are sufficient and economical for

erosion protection. Topsoil should be placed about 100 mm (4 inches) thick. Consult the local

agricultural extension office or the highway department for appropriate types and application rates of

fertilizer and seed.

Slopes greater than 1 vertical to 2 1⁄2 horizontal may require sodding. The engineer should attempt to keep

slopes at 1 vertical to 4 horizontal for erosion and maintenance purposes.

Riprap should be used at corners and intersections of ditches where erosion is likely.

6.7.2 Legal Requirements

Because of the large amount of land under construction each year, erosion and sedimentation control

during construction have become a problem. Many states and localities now have laws or ordinances to

control soil erosion on construction sites and the sedimentation of adjoining waterways.

The engineer should become aware of such state laws, which are usually enforced by the counties. Many

counties have extensive guidelines that have to be strictly adhered to. Consult county agricultural

extension offices for these requirements.

The soil erosion and sedimentation control statutes may mean considerably more engineering time to

develop drawings to show compliance with the requirements of the statute.

6.8 YARD SURFACING MATERIAL

It is desirable to have 100 to 150 mm (4 to 6 inches) of crushed stone or rock cover the entire substation

yard and to extend 1 meter (3 feet) beyond the substation fence. In some locations clam and oyster shell

may also be used. The yard surface material helps reduce the danger of potentially hazardous mesh and
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touch potentials; minimizes weed growth; provides a clean, reasonably dry walking surface during wet

periods; dissipates erosion effect from rain; and contributes to better access drives for light vehicles.

In cases where a more substantial and unlimited drive area is desirable, a 100 mm (4-inch) layer of wellgraded gravel (highway aggregate base course material) is placed and rolled firm. A 75 mm (3-inch)

layer of crushed stone or rock may then be placed on top. In areas where clam and oyster shell is

available, a very durable drive surface is easily obtained.

The size of stone for yard surfacing material should generally vary between 10 mm and 25 mm (3/8 to

1 inch) with the percentage finer than 10 mm (3/8 inch) limited to 5 to 10 percent. Usually the state

highway department has gradations in this range. All faces of yard surface material should be crushed.

Use of round rock (river rock) is to be avoided due to rutting problems.

The material selected for yard surfacing may be affected by the electrical grounding design (see Chapter 9, Grounding, for details). Because of electrical fault currents, surfacing material may need to be

specified differently than would otherwise be the case. It may be desirable to have a 100 to 150 mm (4-

to 6-inch) layer of crushed rock as coarse as can reasonably be walked on with as few fines as practical or

nominally available.

Before the yard surfacing material is installed, the yard surface should be brought to its proposed

elevations and rolled to a reasonably firm condition. A soil sterilizer may be applied to prevent the

growth of grass and weeds at this time. The yard stone or shell should then be spread as evenly as

practical but need not be rolled. This work should not begin until all substation work is essentially

completed.

6.9 SECURITY FENCE

Generally, all outdoor substations are enclosed by a security fence, as discussed in Chapter 2. Safety

clearance requirements for substation fences are covered in Chapter 4.

The fence should be installed as soon as practicable after the site work is completed. This work is usually

done by a fence contractor and is not necessarily a part of the general contract.

A typical specification for material and installation of a chain-link security fence is found in the

Appendix C to this chapter. Bear in mind that numerous other rail, post, and gate frame component

designs will serve at least equally as well as those noted in the typical specification.

6.10 REFERENCES

AASHTO Std. T180, “Standard Method of Test for Moisture-Density Relations of Soils Using a 10-lb

Rammer and an 18-inch Drop.”

American Iron and Steel Institute, Handbook of Steel Drainage and Highway Construction Products, 2d

ed., American Iron and Steel Institute, 1971.

ANSI/IEEE Std. C2, National Electrical Safety Code.

ASTM A36, “Specification for Carbon Structure Steel.”

ASTM A53, “Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated Welded and Seamless.”
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ASTM A121, “Specification for Zinc-Coated (Galvanized) Steel Barbed Wire.”

ASTM A123, “Specification for Zinc (Hot Dip Galvanized) Coating on Iron and Steel Products.”

ASTM A153, “Specification for Zinc Coating (Hot-Dip) on Iron and Steel Hardware.”

ASTM A392, “Specification for Zinc-Coated Steel Chain-Link Fence Fabric.”

ASTM A500, “Specification for Cold-Formed Welded and Seamless Carbon Steel Structural Tubing in

Rounds and Shapes.”

ASTM A501, “Specification for Hot-Formed Welded and Seamless Carbon Steel Structural Tubing.”

ASTM D2-487, “Unified (ASTM) Soil Classification System.”

ASTM F1043, “Standard Specification for Strength and Protective Coatings on Metal Industrial Chain

Link Fence.”

Portland Cement Association, PCA Soil Primer.

U.S. Department of Agriculture, Soil Conservation Service, “Controlling Erosion on Construction Sites,”

Agriculture Bulletin 347.
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APPENDIX C

SAMPLE SUBSTATION SECURITY FENCE SPECIFICATION

S.6.1 GENERAL

This Specification covers the requirements and

general recommendations for material and

erection of security fencing for substations.

The substation fence shall consist of woven steel fabric on steel posts plus barbed wire on extension arms.

It shall be a minimum of 2134 mm (7 feet) high with line posts no greater than 3048 mm (10 feet) apart.

(RUS recommends 8 feet for the fence height: 7 feet of fabric and a 1-foot extension of barbed wire.)

More specific requirements are further described under the Material and Erection sections of this

Specification.

The primary components of the fence are:

1. Fabric

2. Line posts

3. End and corner posts

4. Gate posts

5. Top rail

6. Barbed wire

7. Extension arms

8. Stretcher bars

9. Post braces

10. Tension wire

11. Gate frames

12. Hardware (hinges, latches, stops, keepers, ties, clips, bands)

S.6.2 MATERIAL

S.6.2.1 Fabric

The fence fabric shall be a minimum of 1830 mm (6 feet) high. (RUS recommends 7 feet of fence

fabric.) It shall consist of a minimum No. 9 USWG steel wire, woven into a 51 mm (2-inch) square

mesh. The minimum breaking strength of wire shall be 5338 N (1200 lbs). The sides of the mesh pattern

shall be approximately 45 degrees to a vertical line.

The fabric shall be galvanized in accordance with ASTM A392, Class 2.

S.6.2.2 Line, End, Corner, Pull, and Gate Posts

All posts shall be steel and conform to the sizes as listed in Table 6-3 for the specific type of application.

Strength and protective coatings of all fence framework shall conform to ASTM F1043.

This is a sample specification. Cooperatives should

verify compliance with local standards and check

availability of materials from local suppliers when

writing their specifications.

NOTE: This sample specification calls for a

combination of woven steel fabric and

strands of barbed wire. NESC C2-1997

allows for a 2134 mm (7-foot) woven

steel fabric barrier.
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Table 6-3: Fence Posts for 2134 mm (7-Foot) Fence

Use Type Minimum Size

Round Metric: 60 mm OD; t = 4 mm

English: 2-3/8 in. OD; t = 0.154 in.

Line Posts Square Metric: 50 mm sq; t = 4.25 mm

English: 2 in. sq; t = 0.1875 in.

Rolled or Formed

Section

Size so that bending strength about strong axis is

not less than that of the round post.

Round Metric: 73 mm OD; t = 5 mm

English: 2-7/8 in. OD; t = 0.203 in.

End, Corner, Pull

Posts

Square Metric: 63 mm sq; t = 4.75 mm

English: 2-1/2 in. sq; t = 0.1875 in.

Rolled or Formed

Section

Size so that bending strength about weak axis is

not less than that of the round post.

Round Metric: 100 mm OD; t = 5.75 mm

English: 4 in. OD; t = 0.226 in.

Gate Posts Square Metric: 76 mm sq; t = 6 mm

English: 3 in. sq; t = 0.25 in.

Rolled or Formed

Section

Size so that bending strength about weak axis is

not less than that of the round post.

Tubular material should conform to ASTM A53 Grade B for round shapes and ASTM A500 Grade B or

ASTM A50l for square shapes. Roll-formed sections shall meet the yield stress requirements of ASTM

A36 as a minimum.

Line posts and gate posts shall be of sufficient height to (a) accommodate 1830 mm (6-foot) fabric; (b)

accommodate extension arms or extend 305 mm (1 foot) extra, and (c) be embedded 914 mm (3 feet) into

the concrete footing.

End, corner, and pull posts shall be of sufficient height to (a) accommodate 1830 mm (6-foot) fabric;

(b) accommodate extension arms or extend 305 mm (1 foot) extra, and (c) be embedded 914 mm (3 feet)

into the concrete footing.

All tubular posts shall be galvanized in accordance with ASTM A53. Roll-formed sections shall be

galvanized in accordance with ASTM A123.

S.6.2.3 Top Rail

Top rails shall be round steel pipe or tubing. The minimum size shall not be less than 41 mm

(1 5/8 inches) O.D. nor have a minimum wall thickness less than 4 mm (0.138 inch). Lengths should be a

minimum of 5 meters (16 feet). Provisions for adequately joining lengths together and securing to end or

corner posts shall be compatible for the physical size of the top rail. Top rails shall be galvanized in

accordance with ASTM A53.

S.6.2.4 Barbed Wire

Barbed wire shall consist of two strands of 12-1/2 USWG steel wire with 4-point barbs at a maximum
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spacing of 127 mm (5 inches) apart. The wire shall be galvanized after weaving in accordance with

ASTM A121, Class 3.

S.6.2.5 Extension Arms

The extension arms shall extend upward and outward from the fence at an angle of 45 degrees. There

shall be provisions for three equally spaced lines of barbed wire on the extended arms. The uppermost

wire shall be approximately 305 mm (1 foot) vertically above the fabric.

The extension arm shall be made of pressed steel or malleable iron and should be designed for a 1112 N

(250-lb) minimum pull-down load being applied at arm’s tip.

The extension arm shall be galvanized in accordance with ASTM A153, Class Bl.

S.6.2.6 Stretcher Bar

Stretcher bars shall be galvanized steel bars not less than 6 x 19 mm (1/4 x 3/4 inch). They shall be

approximately 25 mm (1 inch) less than the fabric height.

The stretcher bar shall be used for securing the fabric to all terminal posts. One bar is required for each

gate and end post, and two are required for each corner and pull post.

S.6.2.7 Post Braces

Post braces are required at each gate, corner, pull, and end post. They shall consist of a strut, which shall

not be less in size than the top rail, and a tension rod with turnbuckle. The rod shall be steel and have a

minimum diameter of 10 mm (3/8 inch).

The strut shall be secured to the adjacent line post at approximately mid-height of the fabric. The tension

rod is also secured near this area on the line pole and is anchored near the base of the corner post (or gate,

pull, or end post).

Bracing members shall all be hot-dip galvanized in accordance with ASTM 153.

S.6.2.8 Tension Wire

Tension wire used in lieu of bottom rail shall not be less than No. 7 USWG galvanized steel wire.

S.6.2.9 Gate Frames

Gate frames shall be constructed of tubular steel members that should be welded at the joints. Additional

horizontal and vertical struts may be required to provide for a rigid gate panel allowing for no visible sag

or twist. Gate frames shall be made to have approximately 76 mm (3-inch) clearance above the road.

Fabric for the gate panels shall be the same as for the fence.

Gate frame and bracing members shall not be less than the structural equivalent of 48 mm (1.9-inch) O.D.

standard pipe. Steel tension rods and turnbuckles may also be utilized. Gate frame shall have provisions

for three lines of barbed wire above the fabric. All gate frame material shall be hot-dip galvanized.
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S.6.2.10 Hardware

Hinges shall be heavy duty and allow 180-degree swing of all gate leaves. The hinges shall not twist or

turn under the action of the gate and shall provide ease of operation.

Latches, stops, and keepers shall all be heavy duty construction of galvanized steel or malleable iron.

Latches shall have a heavy-duty drop bar. The center stop shall be made to be cast in concrete and

engage the drop bar. A keeper shall be provided that will secure the free end of the gate in the open

position.

Hardware shall allow for gate operation from either side with provisions for securing with a padlock.

Bands, wire ties, and clips for securing fabric to top rails, line posts, terminal posts, and tension wires

shall be galvanized steel and of adequate strength for the purpose intended. Aluminum wire ties of

adequate strength are acceptable for this work also.

S.6.3 ERECTION

The fabric shall be placed on the outside of the posts, stretched taut, and secured to the posts, top rail, and

tension wire. The fabric shall be secured to the line posts with wire ties or metal bands at maximum

intervals of 356 mm (14 inches). The top and bottom edges shall be secured, respectively, to the top rail

and tension wire with tie wires not exceeding intervals of 610 mm (24 inches). The fabric shall be

secured to terminal posts by means of the stretcher bar that is passed through the end loops of the fabric

and is secured to the terminal posts by metal bands spaced at a maximum interval of 356 mm (14 inches).

Fabric for fencing shall all either be a left-hand or right-hand weave. Rolls of fabric shall be joined

together by weaving a single strand into the end of the roll to form a continuous piece.

The spacing of line posts (3 meters or 10 feet maximum) shall in general be measured parallel to the

ground. All posts shall be placed vertically except as may be specifically designated otherwise, with the

strong axis parallel to the fabric.

All posts shall be set in holes and backfilled with concrete. The concrete shall have a maximum

compressive strength of 1720 N/cm2 (2500 psi) at 28 days with a maximum size of aggregate of 25 mm

(1 inch). The concrete shall be well worked (rodded) in the hole. The top of the footing shall be crowned

to shed water.

The minimum diameter of holes for line posts shall be 229 mm (9 inches) and for terminal posts 305 mm

(12 inches). See Figure 6-6 for erection details.

The minimum depth of the footing holes shall be 965 mm (38 inches).

CAUTION: The engineer should review footing depth in areas subject to extreme frost penetrations and

in areas of solid rock with very little or varying amounts of soft overburden.

S.6.4 GROUNDING

Fence grounding shall be in accordance with Grounding Regulations.
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Figure 6-6: Fence Erection Details
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CHAPTER 7

STRUCTURES

Prior to the start of structure design, several factors should be evaluated that may affect the choice of

material and member type selected for the structure.

Factors influencing selection of material and member type include first cost, cost of erection, deflection

characteristics, cost of maintenance, availability, resistance to corrosion and other deterioration, freedom

from fire hazard, appearance, size of revenue-producing load served, and temporary or permanent nature

of structure.

The American Society of Civil Engineers (ASCE) is currently developing a substation structure design

guide that will discuss in greater detail various structure types, loading criteria, deflection criteria,

methods of structure analysis and design, and structure connection to foundations. The guide is a joint

effort of utilities, manufacturers, consulting firms, and academic research groups. The guide is currently

in rough draft form and is being reviewed by the groups involved.

7.1 MATERIALS

There are four basic materials used for substation structures: steel, aluminum, concrete, and wood.

7.1.1 Steel

Steel is used for most substation structures. Its availability and good structural characteristics generally

make it economically attractive. Steel, however, has to have adequate protection from the elements to

prevent corrosion. Galvanizing and painting are two widely used finishes for steel substation structures.

Because of the protective finish, steel substation structures should not be designed for field welding or

field drilling for connections. Field welding is generally uneconomical and usually requires close control

over the welding conditions.

ASTM A36 steel is the standard grade of steel used for most rolled-shape members in structural design.

Member stresses are usually low, and weight saving is of little advantage. However, should large loads

be encountered, coupled with the need for weight reduction, a high-strength steel should be considered.

Structures requiring such consideration are the line support structures. Structural steel pipe and square

tube sections are normally constructed of ASTM A53 Grade B and ASTM A501 steel, respectively.

7.1.2 Aluminum

Aluminum is sometimes used for substation structures where good corrosion-resistant properties are

desired. It is about one-third the weight of steel.

If aluminum is used, member types should be selected taking advantage of the optimum structural

qualities of aluminum and avoiding the shapes in which aluminum members may be a problem.

Deflection and torsion has to be carefully reviewed when selecting member types in aluminum.

Aluminum has a lower modulus of elasticity, E = 6.9 x 106 N/cm2 (10 x 106 psi), and modulus of

elasticity in shear, E = 2.6 x 106 N/cm2 (3.8 x 106 psi), than steel, Es = 20 x 106 N/cm2 and Es = 8.3 x 106
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N/cm2 (29 x 106 psi and 12 x 106 psi). These properties are directly related to deflection and torsional

rotation.

Structures designed for aluminum are constructed of Alloy 6061-T6 and should be designed, fabricated,

and erected in accordance with the Aluminum Association’s Specifications for Aluminum Structures.

7.1.3 Concrete

Precast, prestressed concrete substation structures may be economical in coastal areas with high winds

and a corrosive environment, and also when substations are located near the fabricator’s plant. Special

considerations are required for the foundation, erection, handling, and equipment mounting characteristics

of the structure.

7.1.4 Wood

Wood may be used for substation structures. Members have to be treated with an appropriate

preservative. Wood poles and members are usually readily available. Structural properties and size

tolerances of wood are somewhat variable, and design considerations should take this into account. The

life of a wood structure is shorter than for steel, aluminum, or concrete, and maintenance costs may be

higher.

Economics is an important consideration when making a material and member type selection. The total

cost over the life of the structure should be considered. This also includes the cost of fabrication and

shipping, ease of erection, and cost of maintenance.

7.2 FUNCTIONAL STRUCTURE TYPES

There are essentially three types of substation structures as categorized from a structural design approach

related to the function served in the substation.

7.2.1 Line Support Structures

These structures are used as line exit structures, internal strain bus structures, and line terminating

structures. They consist basically of two high towers and a crossarm on which the line conductors are

attached. They may be used as single-bay or multibay structures.

The major forces acting on these structures are the shield wire and conductor tensions and wind forces.

Because of their large size and the magnitude of forces acting on them, these structures are usually highly

stressed and require the most design effort.

7.2.2 Equipment Support Structures

These structures are commonly referred to as bus support structures, switch stands, lightning arrester

stands, line trap supports, etc.

In low-profile substation design, these structures are designed primarily as vertical cantilever beams with

wind and short-circuit forces being the primary design forces. Deflection may control the design size of

some structures and should be reviewed in all structures.
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Switch stands should be designed to be more rigid than bus supports or other structures because of the

dynamic loading effect of the switch blade operation and the requirement that the switch blade has to

always return (close) to the relatively small space of the saddle. Any appreciable twisting or deflection of

the switch stand may prohibit this function.

7.2.3 Distribution Substation Structure

This structure is the column and beam structure, similar to a building frame. It may consist of one or

several bays in length and usually is one bay wide. It may vary in height from 6 to 12 m (20 to 40 feet) or

more.

The structure supports switches and other equipment. It usually will have line conductors attached to one

or more sides. This structure should be designed for rigidity and flexibility in equipment location.

Generally these structures are composed of box truss members.

7.3 STRUCTURE MEMBER TYPES

Three types of structure profile configurations are common in substations today. They are classified from

their general physical appearance and structural member components. The types are lattice, solid profile,

and semi-solid profile.

7.3.1 Lattice

The lattice structure consists primarily of angle members forming the chords and lacing of a box truss

acting as a beam or column.

Depending on the function of the structure (i.e., bus support stand vs. line support structure), the design of

the members may or may not be time-consuming and complex.

The lattice structure has been widely used for substation structures for many years. Its box truss beams

and columns allow for an efficient use of material. Usually the lattice structure results in the least

structure weight compared to other line support structures. It is also very stable and rigid. It is very easy

to fabricate, galvanize, and ship. It requires a large amount of bolting and erection time in the field,

unless the members are shipped preassembled, and maintenance painting, if required, is costly. Lattice

structures are also aesthetically displeasing.

7.3.2 Solid Profile

The solid-profile structure is made from wide flange shapes, pipes, tapered round or polygonal shapes,

and rectangular tube shapes. The aesthetic appearance, relatively short erection time, and ease of

maintenance make the solid-profile structure a popular choice for equipment support structures. The

weight penalty on solid-profile equipment support structures is smaller than on line support structures.

The square tube has good torsional resistance and is equal structurally about either major axis. The wide

flange shape has a minor axis that may control the design. It has an open cross section and minimal

resistance to torsional loads.

Wide flange shapes are more suitable for bolted structural connections and may require less welding

during fabrication.
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Line support structures may be made of straight or tapered tubular round or polygonal poles. The tower

may be either an A-frame configuration or a single pole. Wide flange shapes may be used in the A-frame

tower. Crossarms are made of straight or tapered round or polygonal members. A combined section from

wide flange shapes is used for crossarms also.

Tapered poles may have telescoping or flanged splice connections when the pole is galvanized. Painted

poles may have welded splice joints and are hermetically sealed to prevent oxidation inside the pole.

Tapered poles are almost always designed by the pole fabricator to the loading requirements specified by

the engineer.

7.3.3 Semi-Solid Profile

The third structure type is semi-solid profile. This type of structure is made from wide flanges and pipes

or tubes that form the major members, and is braced between these major members with angle bracing.

The design of this structure type is similar to the lattice structure and is very stable and rigid because of

the bracing.

7.3.4 Summary

Each of the structure member types has its advantages and disadvantages, both from an economical and

design viewpoint.

Lattice structures are usually economically comparable in aluminum and steel. The basic design

approach is also the same. Solid-profile structures used for equipment support structures in aluminum

may be as economical as steel in favorable geographical locations. Design effort for aluminum members

used in equipment support structures requires more time because of buckling characteristics and weld

effect on allowable stresses. However, the desirability of aluminum’s good weathering characteristics

and light weight are positive factors that have to also be evaluated.

7.4 DESIGN

7.4.1 Design Loads

Design loads for substation structures should be categorized by:

1. Line support structures

2. Equipment support structures

7.4.2 Line Support Structures

The design loading criteria for these structures should be very similar to the criteria for a transmission line

tower. The maximum loading condition and line tension are usually furnished by the transmission

engineer. For strain bus structures the substation engineer should base the design upon those design loads

that will be a maximum for the various components of the structure.
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A more positive determination of the structure capacity can be made if an overload is applied to the forces

and the structure members are designed utilizing yield stresses. The information is also beneficial for

future line changes for substation upgrading or other electrical load modifications.

The components of this structure should be able to withstand the stresses induced by the most critical

loading (multiplied by an appropriate overload factor) affecting the component member.

These loadings are described in Chapter 2 and are listed here for overload factor correlation.

Overload factors for metal and prestressed concrete structures are as follows:

a. NESC (Heavy, Medium, Light)

1) Wire Pull 1.65

2) Wind 2.50

3) Vertical 1.50

b. High Winds @ 15°C (60°F)

1) Wire Pull 1.3

2) Wind 1.3

3) Vertical 1.3

c. Heavy Ice @ –1°C (30°F)

1) Wire Pull 1.3

2) Vertical 1.3

d. Other Wind & Ice Combination

1) Wire Pull 1.3

2) Wind 1.3

3) Vertical 1.3

e. Seismic Loading

1) All Masses 1.3

The line support structure is designed for two line angle conditions:

1. All wires perpendicular to the crossarm

2. The angle of all wires deviating from perpendicular to the crossarm at 15 degrees

Local conditions may require a larger angular deviation.

7.4.3 Deflection Consideration

In addition to the stresses, the engineer should also consider deflection limitations for line support

structures. Unless particular circumstances dictate otherwise, the limitations listed may be used as

guidelines:
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Crossarms - Δh ≤ 1 to 1-1/2% of span for maximum tension w/ OLF

Poles - (at top) Δh ≤ 4 to 5% of height for maximum tension w/ OLF

Lattice towers and solid-profile A-frame towers usually present no problems with deflection. The singlepole-type line support structure has to be carefully reviewed for deflection limitations, particularly if it is

acting as a line deadend structure and also is supporting backspan conductors.

7.4.4 Lightning Masts

Single tubular poles often are used for tall lightning masts. Give consideration to those poles where no

shield wires are attached.

Include damping devices to reduce or negate vibrational forces created by the wind blowing at or near the

natural frequency of the pole.

One such device may be fairly heavy steel chain, encased in a fire hose (to protect the pole finish) and

suspended from the top of the pole (inside).

7.4.5 Equipment Support Structures

Design these structures for all applicable wind, ice, short-circuit, and dead and dynamic operating loads of

equipment. Steel substation structures generally should conform to the requirements of Part 36 of NEMA

Publication SG 6.

Ice loading is usually not the controlling design load for equipment support structures but should be

reviewed.

Wind loads plus short-circuit forces usually produce the maximum stresses in the structures.

Although not normally a critical factor on bus supports and other stationary type equipment stands,

deflection limitations are important for switch stands. Follow deflection limitations as specified in

Section SG6-36.03 of NEMA Publication SG 6 unless special conditions dictate otherwise.

Design bus support structures and other stationary equipment stands for a reasonable amount of rigidity.

Members stressed to near their allowable stresses may result in structures that perform unsatisfactorily.

Basically, the wind load is assumed for design purposes to be a statically applied load. In reality, it

fluctuates in magnitude, and oscillating motion may be induced in the structures. This motion is most

unpredictable but can be somewhat alleviated by selecting members that may be larger than required by

the calculations and will provide reasonable rigidity for unknown effects. Allowable working stress

design values should be used for equipment support structures.

7.4.6 Base Condition

Equipment support structures consisting of solid-profile members may be designed either with the base

plate in full contact with the foundation or resting on leveling nuts slightly above the foundation.

The design with the leveling nuts has several advantages:
Bulletin 1724E-300

Page 437

a. It eliminates need for close tolerance work on foundation elevation and trueness of surface.

b. It allows for some flexibility for structure alignment as a result of fabrication tolerances and

buswork fit up.

c. The base plate is not resting in any standing water on the foundation.

Anchor bolt sizes may be required to be slightly larger because of additional bending stress induced. The

space between the bottom of the leveling nut and the nominal top of the foundation is usually 1.3 cm

(1⁄2 inch).

7.4.7 Seismic Loads

Designing structures for seismic loading can be a very involved, time-consuming procedure involving

dynamic analysis and response spectra. In certain areas of high seismic risk or when sensitive equipment

is to be installed, such analysis may be necessary; however, it should be performed by trained, competent

people. For most design purposes, more simplified methods can be used, such as those found in the

ASCE Substation Design Guide, which is currently being updated and revised. The discussion presented

here is based on the 1998 draft version of the ASCE Substation Design Guide.

Seismic or earthquake loads are environmental loads that are governed by the region of the country in

which they occur. In substation design, seismic loads are not usually combined with ice and wind loads,

but may be combined with short-circuit forces or operating loads if these loads can occur as a result of

seismic activity.

The United States is broken into six seismic regions as shown in Figure 2-2, UBC Seismic Zone Map of

the United States. A zone factor, Z, ranging from 0.0 to 0.4 is determined based on the site location. The

zone factor is equivalent to the zero period acceleration (ZPA) of the ground motion. Values of “Z” are

indicated in Table 7-1.

Table 7-1: UBC Seismic Zone Factors. Ref. Uniform Building Code, 1997, Table 16-I.

Reproduced from the 1997 edition of the Uniform Building CodeTM, copyright © 1997,

with permission of the publisher, the International Conference of Building Officials.

Zone 0 1 2A 2B 3 4

Z 0 0.075 0.15 0.20 0.30 0.40

Substation structures are divided into four types when considering seismic loading criteria:

1. ST1 Single- or Multi-Bay Rack (Not supporting equipment)

2. ST2 Single- or Multi-Bay Rack (Supports equipment and/or conductors)

3. ST3 Rigid Isolated Support (Supports equipment)

4. ST4 Flexible Isolated Support (Supports equipment)

Rigid and flexible isolated supports (ST3 and ST4) in voltage classes greater than 121 kV, and within

Seismic Zones 3 and 4, should be designed and qualified according to IEEE Std. 693, “Recommended

Practices for Seismic Design of Substations.” For these structures, the procedure below can be used as a

check against wind and ice load cases to determine controlling load cases, but IEEE Std. 693 should be

used for final design.

The design procedure described below can be used for the design of:
Bulletin 1724E-300

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1. Rigid isolated supports and flexible isolated supports (Types 3 and ST4) in Seismic Zones 1,

2A, and 2B.

2. Rigid isolated supports and flexible isolated supports (Types 3 and ST4) for equipment in

voltage classes 121 kV and below in Seismic Zones 3 and 4.

3. Racks (single- or multi-bay) and A-frames (Types ST1 and ST2) in all Seismic Zones. The

design base shear is determined using Equations 7-1 and 7-2:

Equation 7-1

Equation 7-2

Where:

V = Total design lateral force or shear at the base

Z = UBC Seismic Zone Factor

Rw = Structure Type Factor

C = Numerical Coefficient (C need not exceed 2.75)

S = Site Coefficient for Soil Characteristic, see Table 7-2

T = Fundamental Period of Vibration, in seconds

I = Importance Factor

W = Seismic Dead Load (including all rigidly attached equipment or conductor;

flexible attachments, such as conductor, need not be included)

Table 7-2: Site Coefficient for Soil Characteristics. Ref. Uniform Building Code, 1997, Table 16-J.

Reproduced from the 1997 edition of the Uniform Building CodeTM, copyright © 1997,

with permission of the publisher, the International Conference of Building Officials.

Description S Factor

Rock-like material, Shear Wave velocity greater than 2,500 fps

or

Medium-dense to dense or medium-stiff soil conditions, depth less than 200 feet

1.0

Predominantly medium-dense or medium-stiff to stiff soil conditions, depth

exceeds 200 feet 1.2

Soil profile containing more than 20 feet of soft to medium-stiff clay but not more

than 40 feet of soft clay 1.5

Soil profile containing more than 40 feet of soft clay, shear wave velocity less than

500 fps 2.0

The Importance Factor, I, is taken as 1.0 (based on UBC Life Safety), 1.25 (based on UBC Life Safety

and functional performance after a seismic event), or 1.5 (same basis as 1.25 but for anchorage systems),

depending on the importance of the structure to the electric system. The numerical coefficient, C, may be

assumed to be 2.75 if the soil conditions are unknown, regardless of the soil type or period.

The Structure Type Factor, Rw, is based on the lateral force resisting system of the structure. Tables 16-N

and 16-P in the Uniform Building Code provide a complete list of values to be used. Substation structures

can be generally classified as shown in Table 7-3:

W

R

ZIC V

w

=

2 / 3 T

1.25S

C =
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Table 7-3: Structures—Type Factor.

Ref. Uniform Building Code, 1997, Table 16-P.

Reproduced from the 1997 edition of the Uniform Building CodeTM, copyright © 1997,

with permission of the publisher, the International Conference of Building Officials.

Structure Type Rw

Moment-Resisting Steel Frame 6

Trussed Towers 4

Raised Tanks or Inverted Pendulum 3

Conservatively, it is recommended that a value of Rw = 4 be used for most rack-type structures

(Types ST-1 and ST-2). Structures such as an isolated bus support (freestanding inverted-pendulum)

could use a value of 3.

7.4.8 Wind Loads

Several methods of determining wind loads are used. One widely used method is found in NEMA

Std. SG6, Part 36, “Outdoor Substations.”

Wind pressures on flat surfaces are obtained from Equations 7-3 and 7-4:

Equation 7-3 Equation 7-4

Pw = 0.0776V2(Metric) Pw = 0.0042V2(English)

Wind pressures on cylindrical surfaces are obtained from Equations 7-5 and 7-6:

Equation 7-5 Equation 7-6

Pw = 0.0481V2(Metric) Pw = 0.0026V2(English)

Where:

Pw = Pressure on the projected area, N/m2 (psf)

V = Design wind velocity, km/hr (mph)

The design wind velocity for a given area is determined from the probable wind velocity over the design

life of the structure, say a 50-year period of recurrence. This information can be obtained from Figure 2-1

or may be derived from local climatological data.

For wind loading on lattice structures, the projected area used is one and one-half times the area of

exposed members.

An alternative approach to calculating wind load on substation structures can be found in the ASCE

Substation Design Guide, currently under development. The approach in this guide is based on

ANSI/ASCE Std. 7-95, “Minimum Design Loads for Buildings and Other Structures.”

Under the ANSI/ASCE Std. 7-95 approach, the “3-second gust” wind speed at a height of 10 meters

(33 feet) is used as the basic wind speed for design replacing the “fastest mile” wind speed data in the

ASCE Std. 7-93 basic wind speed map. The basic wind speed to be used can be obtained from Figure 2.1. Based on the ASCE Substation Design Guide and ANSI/IEEE Std. 605, “IEEE Guide for Design

of Substation Rigid Bus Structures,” the wind load on a structure can be determined using Equation 7-7:
Bulletin 1724E-300

Page 440

Equation 7-7

Pw= CCDKZGFV

2

I

Where:

W = Wind pressure N/m2 [lb/ft2]

C = 6.13*10-1 for metric units [2.56*10-3 for English units]

CD = Drag coefficient

KZ = Height and exposure factor

GF = Gust factor

V = Basic wind speed at 10 meters [33 feet] above ground, m/hr [mi/hr]

I = Importance factor

Each of the above variables is briefly discussed below.

Constant, C. This is a constant that yields a value for FW in terms of metric or English units.

Drag coefficient, CD. The wind load on a conductor or a structure varies with its shape. The drag

coefficient reflects that variation. The coefficient can vary between 1.0 for round, smooth shapes to about

2.0 for flat surfaces. For a more detailed discussion of the variation in values to use, see ANSI/IEEE

Std. 605 or ASCE Std. 74, Guidelines for Electrical Transmission Line Structural Loading.

Height and exposure factor, KZ. In the height range from 0 meters [feet] to 9.1 meters [30 feet] and for

exposure categories A, B, and C, the height and exposure factor KZ = 1.0. For exposure category D, KZ =

1.16. Each of these exposure categories is explained in detail in ANSI/ASCE Std. 7-95. A summary

description is provided below:

Exposure A: Large cities’ centers with at least 50 percent of the structures having a height greater

than 21.3 meters [70 feet].

Exposure B: Urban and suburban areas, wooded areas, or other terrain with numerous closely

spaced obstructions having the size of single-family dwellings or larger.

Exposure C: Open terrain with scattered obstructions having heights generally less than 9.1 meters

[30 feet]. Open country and grassland is included in this category.

Exposure D: Flat, unobstructed areas exposed to wind flowing over open water for a distance of at

least 1.61 km [1 mile].

Gust factor, GF. A gust factor of 0.8 should be used for exposure categories A and B, and 0.85 should be

used for exposure categories C and D.

Basic wind speed, V. Figure 2-1 should be used for this value.

Importance factor, I. An importance factor of 1.15 should be used for electric substations. See

ANSI/ASCE Std. 7-95 for a discussion of the importance factor.

7.4.9 Construction Loading

Consideration should also be given to construction loads that can be periodically imposed on structures

such as pulling and hoisting equipment into place. While such conditions do not usually govern design,
Bulletin 1724E-300

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they should be evaluated.

7.4.10 Loading Combination for Design

In addition to designing equipment stands for the extreme loads, bus supports are also designed for a

combination load of extreme wind and short-circuit loads. The load combination design should be

limited to calculations of stress and should not consider deflection of the structure.

7.4.11 Typical Design Approach

There are basically two approaches to design of steel structures: Allowable Stress Design (ASD) and

Load and Resistance Factor Design (LRFD).

The ASD approach is defined by the American Institute of Steel Construction’s (AISC) Manual of Steel

Construction, ASD. In the ASD, the stresses induced by various service loads (wind, ice, etc.) in a

selected member are compared to allowable stresses established in the AISC manual.

In LRFD, load factors are applied to the service loads, or loads the structure is actually expected to see.

Then a member is selected that will have sufficient strength to resist the factored loads. In addition, the

theoretical member strength is reduced by an applied resistance factor. The selection of the member has

to satisfy the following:

Factored load < Factored strength

The “factored load” is the sum of all the working loads to be resisted by the member. Each load is

multiplied by its own load factor. Dead loads, for example, will have load factors that are different from

live load factors. The “factored strength” is the theoretical strength multiplied by a resistance factor.

Load and Resistance Factor Design of steel structures is very much similar to the approach to reinforced

concrete design used for several years in the American Concrete Institute’s Building Code where it is

known as strength design.

The benefit of ASD is that it is straightforward and familiar to most structural engineers. With the LRFD

approach, load factors model the likelihood, or probability of certainty, of various types of loads. For

example, dead loads can typically be determined with more certainty than can live loads. Therefore, the

load factor for a dead load is less than that for a live load.

The resistance factors applied to the member’s theoretical strength account for uncertainties in material

properties, design theory, and fabrication and construction practices. One might say that the LRFD is a

more realistic approach to structure design. The guidelines and specifications for LRFD are published in

AISC’s Manual of Steel Construction, Load Factor & Resistance Factor Design.

Several examples are illustrated depicting the design of the main member for a single-phase bus support.

These examples show a typical approach for the design of most equipment support structures using

allowable stress design. The examples include a square tube, a wide flange, and a lattice column, all

composed of steel.

Lighter weight members may still meet the loading and deflection criteria. However, smaller size

members may present fabrication problems in the lattice structure.
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In general, for voltages up to 230 kV, structures using tubular members are as economical as lattice or

wide flange structures when weight, ease of fabrication, and ease of erection are considered.

7.4.11.1 Design Example: Design a single-phase bus support for a substation in Lansing, Michigan,

given the following information:

• Height of bus centerline above foundation 5.5 m (see Figure 7-1)

• Schedule 40 aluminum bus 100 mm (mass = 5.51 kg/m)

• Maximum short-circuit force 550 N/m

• Short-circuit reduction factor 0.66

• Bus support spacing 6.0 m

• Insulator 2.0 m high, 0.28 m diameter, and 140 kg

Figure 7-1: Single-Phase Bus Support

a. Design a tubular structure, A500 or A501 steel.

Short-Circuit Loading

Fsc = 6.0 m x 0.66 x 550 N/m = 2178 N

Mom @ base = 5.5 m x 2178 N = 11,980 N-m

Wind Loading

Extreme 50-year wind 112.6 km/hr

For flat surfaces: Pw = 0.0776 (112.6)2 = 984 N/m2

For cylindrical surfaces: Pw = 0.0481 (112.6)2 = 610 N/m2
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Figure 7-2: Tubular Structure—Short-Circuit Loading

Figure 7-3: Tubular Structure—Wind Loading

Description Force

Moment

Arm

Moment

@ Base

Wind on Bus 6m x 610 N/m2 x 0.1 m2/m = 366 N 5.5 m 2013 Nm

Wind on Insulator 2m x 610 N/m2 x 0.28 m2/m = 342 N 4.4 m 1505 Nm

Wind on Structure

(assume 20 cm square) 3.4m x 984 N/m2

 x 0.20 m2/m = 669 N 1.7 m 1137 Nm

TOTALS 1377 N 4655 Nm
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Heavy Ice Loading (25.4 mm)

Figure 7-4: Tubular Structure—Ice Loading

Ice density = 913.0 kg/m3 (57 pcf)

Description Load

Ice on Bus 9.14 kg/m

Ice & Bus 14.65 kg/m

Ice on Insulator 22.34 kg/m

Ice & Insulator 184.7 kg

( )

2

cm

kg/m x m kg m x kg/m N/kg

14.5

14.65 6.0 184.7 3.4 28.89 9.80

f

a

+ +

=

2

250.6

cm

N

=

( )

84

8.05

340

= 2 =

cm

cm

r

kl

okay

cm

N

cm

N

Fa 10335 250.6 2 2= >

[( ) ( ) ] =

π

−

2 2 3

x 913 kg / m

4

0.151 m 0.100 m

[( ) ( ) ] =

π

−

2 2 3

x 913 kg/ m

4

0.331m 0.28 m

9.14 kg/ m + 5.51 kg/ m =

22.34 kg /m x 2m + 140kg =
Bulletin 1724E-300

Page 445

Seismic Loading

Figure 7-5: Tubular Structure—Seismic Loading

V = 0.08W

Z = 0.075 (Lansing, Michigan, is in Zone 1)

I = 1.15

C = 2.75 (assumed)

Rw = 3

Description Force

Moment

Arm

Moment

@ Base

Seismic on Bus 6 m x (5.51 kg/m) 9.8 (0.08) = 25.9 N 5.5 m 142.4 Nm

Seismic on Insulator 140 kg (9.8) 0.08 = 109.8 N 4.4 m 483.1 Nm

Seismic on Structure 3.4 m (28.89 kg/m) 9.8 (0.08) = 77.0 N 1.7 m 130.9 Nm

TOTALS 132.9 N 756.4 Nm

The combined loading of wind and short-circuit forces produce the greatest forces and moment at the base

design for this condition. Therefore, heavy ice and seismic forces are not critical for this structure.

For the cantilever structure, bending and deflection are the principal concerns.

Try a 20.3 cm x 20.3 cm x 0.48 cm steel tube:

( )

3 2

cm

N

cm

Nm cm/m

S

M

7100

234.3

16,635 10 f

b = = =

okay

cm

N

cm

N

Fb Fy 0.60 15160 7100 2 2= = >

W

R

ZIC V

w

=

W

3

0.075(1.5)(2.75)

V =
Bulletin 1724E-300

Page 446

Check Deflection

(For wind only)

Figure 7-6: Tubular Structure—Deflection Equivalent Loadings

Deflection Equivalent Loadings

Δ @ end of steel = Δ1 + Δ2 + Δ3

Δ = 0.19 cm + 0.07 cm + 0.13 cm = 0.39 cm

, Wind on insulator and bus

3EI

Pl Where:

3

Δ1 =

, Uniform wind on structure

8EI

Wl4

Δ2 =

, Moment at insulator base

2EI

Ml2

Δ3 =

( ) Θ @ = Θ1 + Θ2 + Θ3slope end of steel

, Wind on insulator and bus

2EI

Pl Where :

2

Θ1 =

, Uniform wind on structure

6EI

Wl3

Θ2 =

, Moment at insulator base

EI

Ml Θ3 =
Bulletin 1724E-300

Page 447

Θ = 0.00086 rad + 0.00027 rad + 0.00079 rad = 0.00192 rad

Δ @ top of insulator = 0.39 cm + 200 cm sin Θ = 0.77 cm

Acceptable criteria for bus support structure deflections may be taken as 1/200 of the bus height.

The analysis shows that for the given conditions a structural tube 20.3cm x 20.3cm x 0.48cm will be

suitable.

b. Design a wide flange structure using A36 steel.

The maximum combined loads on this structure are the same as in the first example. Again, by

inspection, heavy ice loading is not critical. Therefore, consider only bending and deflection.

Assume W 20.3cm x 35.7 kg/m

Fb is reduced when the unbraced compression flange is considered

Check Deflection

(For wind only)

Δxx @ end of steel = 0.13 cm + 0.05 cm + 0.09 cm = 0.27 cm

Θ = .00060 rad + 0.00019 rad + 0.00055 rad = 0.00134 rad

Δxx @ insulator = 0.27cm + 200 cm sin Θ = 0.54 cm

okay

cm

cm

200

1

714

1

550

0.77

= <

( )

3 2

xx

bxx

cm

N

4878

341cm

16,635 Nm 100 m / m

S

M f = = =

( )

(wind only )

cm

N

cm

Nm cm/m

S

M

3 2

yy

2872

92

2642 100

f

byy = = =

F 14,200 N / cm 4878 N / cm okay 2 2

bxx = >

N/cm N/cm okay 2 2Fbyy = 15,170 > 2872

okay

cm

cm

200

1

926

1

500

0.54

= <
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Page 448

c. Design a lattice structure, A36 steel (assume box truss 38.1 cm square).

Figure 7-7: Lattice Structure

Short-Circuit Loading

Fsc = 6.0 m x 0.66 x 550 N/m = 2178 N

Figure 7-8: Lattice Structure—Short Circuit Loading

Mom @ base = 5.5 m x 2178 N = 11,980 Nm
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Page 449

Wind Loading

Assume chord angles = 6.35 cm

Assume lacing angle = 4.45 cm

Figure 7-9: Lattice Structure—Wind Loading

Description Force

Moment

Arm

Moment

@ Base

Wind on Bus 6 m x 610 N/m2 x 0.1 m2/m = 366 N 5.5 m 2013 Nm

Wind on Insulator 2 m x 610 N/m2 x 0.28m2/m = 342 N 4.4 m 1505 Nm

Wind on Structure 3.4m x 1476 N/m2 x 0.19m2/m = 953 N 1.7m 1620 Nm

TOTALS 1661 N 5138 Nm

By inspection, heavy ice and seismic loading will not result in the maximum design loads.

Moment at the base causes tension and compression in the chord angles.

C = Tensile or compressive force

P = Applied load

[ ( )]

24,250N per leg

2 0.381m 2 0.014 m

17,118 Nm C =

−

=

( )

leg

N

N

N m N/m P C 24,250 24,670

4

1373 6 54

+ =

+

+ =

( ) ( )

a 2

z y cm

N

30 F 13,780

1.98

1.0 57

r

kl 30

1.26

1.0 38.1

r

kl

= = = = =

okay

cm

N

cm

N

cm

N

f

a 2 2 2

4153 13,780

5.94

24,670

= = <
Bulletin 1724E-300

Page 450

Δ @ top of steel = 0.07 cm + 0.03 cm + 0.05 cm = 0.15 cm

Θ = 0.00030 rad + 0.00010 rad + 0.00028 rad = 0.00068 rad

Δ @ top of insulator = 0.15 cm + 200 cm sin Θ = 0.29 cm

A summary of mass and deflection for the structure design example is shown in Table 7-4.

Table 7-4: Summary of Mass and Deflection—Design Example

Description

Mass of

Structure

Deflection at

Insulator Comments

20.3 cm x 20.3 cm x 0.48 cm 122 kg 0.77 cm Largest deflection

W20.3 x 35.7 kg/m 154 kg 0.54 cm Heaviest structure

Box Truss, Chord Angles

6.35 cm x 6.35 cm x 0.48 cm

Lacing Angles

4.45 cm x 4.45 cm x 0.48 cm

118 kg 0.29 cm Smallest deflection

7.5 FASTENERS

Three types of structural bolts are typically used in substation structure design. These bolts are

designated by ASTM Standard Specifications A394, A307, and A325. For all but the most severely

loaded structures, the A394 and A307 bolts will usually be adequate.

If possible, one type of structure bolt and one diameter should be used in any one structure and

throughout all the substation structures.

7.5.1 ASTM A394

ASTM Standard Specification A394 covers galvanized hex head bolts including hex nuts with sizes from

12.7 to 25.4 mm (1⁄2 to 1 inch) in diameter.

7.5.2 ASTM A307

Non-galvanized regular square or hex head bolt and nuts in diameters ranging from 6.35 to 101.6 mm (1⁄4

to 4 inches) in diameter are covered by ASTM Standard Specification A307. This specification is also

used for anchor bolts conforming to the requirements of ASTM A36 structural steel. For substation

usage, Grade A bolts are used. Hot-dip galvanizing in accordance with ASTM A153 is required for

substation applications.

7.5.3 ASTM A325

When high-strength bolts are required, ASTM Standard Specification A325 High Strength Bolts may be

used. High-strength bolts are available in sizes from 12.7 to 38.1 mm (1⁄2 to 11⁄2 inches) in diameter.

Bolts, nuts, and washers should be galvanized in accordance with ASTM A153, Class C. Nuts should

conform to ASTM A563, Grade DH.

okay

cm

cm

200

1

1897

1

550

0.29

= <
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Page 451

Some tabulated bolt values for single shear are given in Table 7-5. These values may be used for

substation structure design when “working stresses” or “yield stresses” are used.

Table 7-5: Suggested Allowable Bolt Shear

SINGLE SHEAR ON BOLTS, KIPS (English Units)

WORKING STRESS DESIGN

Nominal Diameter (inches) ASTM

Designation

Allowable Shear

Stress

Fv (ksi) 1⁄2 5/8 3⁄4 7/8 1

A307 10.0 1.96 3.07 4.42 6.01 7.85

A394 15.0 2.95 4.60 6.63 9.02 11.78

A325 21.0 4.12 6.44 9.28 12.63 16.49

SINGLE SHEAR ON BOLTS, KIPS (English Units)

YIELD STRESS DESIGN

Nominal Diameter (inches) ASTM

Designation

Allowable Shear

Stress

Fv (ksi) 1⁄2 5/8 3⁄4 7/8 1

A307 18.0 3.53 5.52 7.95 10.82 14.14

A394 30.0 5.89 9.20 13.25 18.04 23.56

A325 36.0 7.07 11.05 15.91 21.64 28.28

SINGLE SHEAR ON BOLTS, kN (Metric Units)

WORKING STRESS DESIGN

Nominal Diameter (mm) ASTM

Designation

Allowable Shear

Stress

Fv (kN/ cm2)

12.70 15.88 19.05 22.23 25.40

A307 6.89 8.73 13.65 19.65 26.75 34.94

A394 10.34 13.10 20.46 29.46 40.09 52.37

A325 14.48 18.35 28.66 41.27 56.17 73.37

SINGLE SHEAR ON BOLTS, kN (Metric Units)

YIELD STRESS DESIGN

Nominal Diameter (mm) ASTM

Designation

Allowable Shear

Stress

Fv (kN/ cm2)

12.70 15.88 19.05 22.23 25.40

A307 12.41 15.73 24.57 35.38 48.15 62.90

A394 20.68 26.21 40.94 58.96 80.24 104.81

A325 24.82 31.45 49.12 70.74 96.28 125.75

Based on:

1. AISC Manual of Steel Construction, ASD, 9th ed.

2. AISC Manual of Steel Construction, RLFD, 2d ed.

3. ASTM A394 Standard Specification for Steel Transmission Tower Bolts.

4. ASCE Manuals and Reports on Engineering Practice No. 72, Design of Steel

Transmission Pole Structures, 2d ed.
Bulletin 1724E-300

Page 452

Because of the repeated loads, those structures using A307 or A394 bolts should also incorporate either

lockwashers or locknuts to prevent loosening of the connections. Standard washers are not normally used

with these bolts.

7.6 WELDING

All welding of structural steel should be in accordance with the latest edition of the Structural Welding

Code, D1.l of the American Welding Society.

In addition to the required design welds, structures that are to be galvanized should have all joints sealed

with a small continuous seal weld. This is to help prevent corrosion or small crevices or cracks between

two pieces of abutting steel that the acid bath can penetrate, but not the molten zinc. This is covered in

ASTM A385.

7.7 FINISHES

7.7.1 Galvanizing

Galvanized steel has found wide application for substation structures. Hot-dip galvanizing has been the

most widely used finish on steel substation structures for the following reasons:

a. It is economical (initial cost, touch-up, and general maintenance).

b. It provides good resistance to most corrosive environments.

c. It has “self-healing” properties against minor abrasions.

d. It requires little or no maintenance in most substation applications.

New structures are galvanized in accordance with ASTM Standard Specification A123. Safeguards

against embrittlement and warpage and distortion during galvanizing should be in conformance with

ASTM Standard Specification A143 and A384, respectively. Galvanized members that are marred in

handling or erection or that have had corrective work done should be touched up with a zinc-rich paint.

All bolts and steel hardware should be galvanized in accordance with ASTM Standard Specification A153

for Class C material.

7.7.2 Painting

When painted structures are desired, there are several systems available. Consultation with reputable

paint suppliers is recommended. Painting System Specification No. 1.04, SSPC –PS 1.04, from the Steel

Structures Painting Council is one paint system that is applicable for galvanized and non-galvanized

substation structures. The following is a summary of the system from the seventh edition of the Steel

Structures Painting Council’s Systems and Specifications manual.

Surface Preparation: The surface shall be thoroughly cleaned of all oil, grease, dirt, loose mill scale,

and other detrimental substances. “Hand tool cleaning” is the minimum

surface preparation required for this oil-based system. Depending upon

condition of the surface “power tool cleaning” may be necessary. “Solvent

cleaning” is only required for new galvanized structures. Specifications for

these cleaning systems are outlined in the SSPC manual.
Bulletin 1724E-300

Page 453

Paints:

Primer: The system calls for a zinc dust–zinc oxide primer that conforms to federal

specification TT-P-641G Type 1, which is a linseed oil primer.

Intermediate Coat: This second coat uses SSPC-Paint 104, which is a white or tinted alkyd paint

that has good weathering ability and is suitable for exterior exposures. This

paint is intended for brush or spray applications and works well as either an

intermediate or top coat. There are four types that are color dependent:

Type 1 – white

Type 2 – medium to light gray to tan

Type 3 – light green

Type 4 – dark or forest green

Finish Coat: Same as intermediate coat, but the color has to be specified.

Dry Film Thickness: This three-coat paint system calls for a minimum paint thickness of 4.5 mils.

This consists of a 2.0 mil primer coat, a 1.5 mil intermediate coat, and a 1.0 mil

finish coat. The measurements shall be in accordance with SSPC-PA 2,

“Measurement of Dry Paint Thickness with Magnetic Gages.”

Painted structures should be primed and receive the intermediate coat in the shop. The finish coat may

either be applied in the shop or in the field. The finish coat can be applied under ideal conditions in the

shop; however, the structure finish may be marred during shipment or erection requiring field touch-up.

The SSPC manual gives additional specifications for touch-up painting and maintenance painting as well

as providing alternative finish coat systems.

7.7.3 Wood Preservatives

Wood preservatives for poles shall conform to that specified in RUS Bulletin 1728F-700, “Specification

for Wood Poles, Stubs and Anchor Logs” (Electric).

All other timber shall be fully treated in accordance with RUS Bulletin 1728H-701, “Specification for

Wood Crossarms (Solid and Laminated), Transmission Timbers and Pole Keys” (Electric). Where

framing and drilling are necessary for construction purposes, an approved preservative should be applied

to the exposed, untreated wood.

7.8 COMPUTER PROGRAMS

Today, computers are widely used in the design of substation steel structures. Though there are numerous

design programs available for use on a personal computer, most of them use a basic approach.

7.8.1 Model Geometry

The structure, whether a simple bus support or a more involved multi-bay switch rack, is defined by

nodes (or joints) and by members (or elements). The nodes are either automatically numbered by the

program or are defined by the user. Most programs accommodate a three-dimensional model, and the

nodes are located in a Cartesian coordinate system by input of X, Y, and Z coordinates. The members are

then defined and “connected.” Member end points (node numbers) are identified, and the members are

assigned numbers, either by the program or the user. Material properties, such as the modulus of
Bulletin 1724E-300

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elasticity, weight density, and the allowable yield stress, are then defined. In many programs the material,

such as concrete, wood, or steel, can be selected from a menu and all the properties automatically defined.

After material properties are defined, section properties of the members are then input. Section properties

include cross-sectional area, moment of inertia, and torsional properties. Most programs allow the user to

identify a standard AISC cross section, for example W8X31, with all the associated section properties

built into the program’s database. After node, member, and section properties are defined, the member

end restraints and base fixity are defined. Members are considered “fixed,” or rigid and continuous unless

the end of the member is released in rotation or translation by the user. A column base restraint is defined

on the basis of the connection details. If it is firmly fixed with four anchor bolts with the column welded

directly to the base plate, the end restraint can be defined in the model as fixed. However, if the column

is connected to the base plate by two anchor bolts, the end restraint can be modeled with a pinned

connection, or free to rotate but restrained in translation.

7.8.2 Load Input

Loads are applied to the structure as either point or distributed loads. With modern structural analysis

programs, the point loads can be linear loads (kN) or applied moments (kN-m) in any direction anywhere

along the length of the member. Distributed loads can be uniform or can vary in magnitude, and can be

applied over all or any portion of the member. Various load cases are defined, such as extreme wind, ice

loads, equipment, and gravity loads, and then these separate load cases are combined along with

appropriate load factors.

7.8.3 Computer Output

After the computer model of the structure has been created and the loads entered, the program is

executed. The output from a structural analysis program provides all the information needed by the

engineer to completely design the structure. The information typically includes forces at each joint (axial

forces, shear, and bending moments) and structure reactions to be used in foundation design. Also

included are member stresses and deflections at various points along the member. Some programs

provide AISC stress checks and suggested member sizes to be used in a subsequent iteration of the

program.

As noted above, there are many structural analysis programs available on the market. A small sample of

these are listed below. Sample input and output from RISA-3D for a simple “T” structure provided for

reference can be found in the Appendix D to this chapter.

SAP2000

Computers and Structures, Inc.

1995 University Ave.

Berkley, CA 94704

Phone: (510) 845-2177

STAAD-III

Research Engineers

22700 Savi Ranch

Yorba Linda, CA 92887-4608

Phone: (714) 974-2500

RISA-3D

RISA Technologies

26212 Dimension Drive, Suite 200

Lake Forest, CA 92630

Phone: (800) 332-7472

StruCAD*3D

Zentech, Inc.

8582 Katy Freeway, Suite 205

Houston, TX 77024

Phone: (713) 984-9171
Bulletin 1724E-300

Page 455

7.9 REFERENCES

Aluminum Association, “Aluminum Standards and Data.”

Aluminum Association, Specifications for Aluminum Structures.

American Concrete Institute, Building Code. Farmington, Mich.: ACI, 1995.

American Institute of Steel Construction (AISC), Manual of Steel Construction, AISC M016-1989, ASD,

9th ed.

American Institute of Steel Construction (AISC), Manual of Steel Construction, Load Factor &

Resistance Factor Design, AISC M015.

American Institute of Steel Construction (AISC), “Specification for the Design, Fabrication and Erection

of Structural Steel for Buildings,” AISC S326-1978.

American Institute of Timber Construction Std. 102, “Standards for the Design of Structural Timber

Framing.”

American Institute of Timber Construction Std. 116, “Guide Specifications for Structural Glued

Laminated Timber for Electric Utility Framing.”

American Institute of Timber Construction, Timber Construction Manual.

American Society of Civil Engineers (ASCE), Substation Design Guide (under revision).

American Society of Civil Engineers (ASCE), ASCE Std. 7-93, “Basic Wind Speed Map.”

American Society of Civil Engineers (ASCE), ASCE Std. 74, “Guidelines for Electrical Transmission

Line Structural Loading.”

American Society of Civil Engineers (ASCE), “Design of Steel Transmission Pole Structures.”

American Society of Civil Engineers (ASCE), Electrical Transmission Line and Tower Design Guide.

American Society of Civil Engineers (ASCE), Substation Structure Design Guide (under development).

Draft 1998.

American Society of Civil Engineers (ASCE), Manuals and Reports on Engineering Practice No. 72,

“Design of Steel Transmission Pole Structures,” 2d ed.

American Welding Society Std. Dl.l, Structural Welding Code.

ANSI/ASCE Std. 7-95, “Minimum Design Loads for Buildings and Other Structures.”

ANSI/IEEE Std. C2, National Electrical Safety Code.

ANSI/IEEE Std. 605, “IEEE Guide for Design of Substation Rigid-Bus Structures.”
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ASTM Std. A36, “Specification for Structural Steel.”

ASTM Std. A53, “Specification for Pipe, Steel, Black and Hot-Dipped, Zinc Coated Welded and

Seamless Steel Structure.”

ASTM Std. A123, “Specification for Zinc (Hot-Galvanized) Coatings on Products Fabricated From

Rolled, Pressed and Forged Steel Shapes, Plates, Bars and Strip.”

ASTM Std. A143, “Recommended Practice for Safeguarding Against Embrittlement of Hot-Dip

Galvanized Structural Steel Products and Procedure for Detecting Embrittlement.”

ASTM Std. A153, “Specification for Zinc Coating (Hot-Dip) on Iron and Steel Hardware.”

ASTM Std. A307, “Specification for Carbon Steel Externally and Internally Threaded Standard

Fasteners.”

ASTM Std. A325, “Specification for High-Strength Bolts for Structural Steel Joints, Including Suitable

Nuts and Plain Hardened Washers.”

ASTM Std. A384, “Recommended Practice for Safeguarding Against Warpage and Distortion During

Hot-Dip Galvanizing of Steel Assemblies.”

ASTM Std. A385, “Practice of Providing High-Quality Zinc Coatings (Hot-Dip).”

ASTM Std. A394, “Specification for Galvanized Steel Transmission Tower Bolts and Nuts.”

ASTM Std. A501, “Specification for Hot-Formed Welded and Seamless Carbon Steel Structural Tubing.”

ASTM Std. A563, “Specification for Carbon and Alloy Steel Nuts.”

Federal Specifications and Standards No. TT-P-57B, “Paint, Zinc Yellow-Iron Oxide-Base, Ready

Mixed.”

Federal Specifications and Standards No. TT-P-641D, “Primer Coating: Zinc Dust-Zinc Oxide (for

Galvanized Surfaces).”

IEEE Std. 693, “Recommended Practices for Seismic Design of Substations.”

NEMA Std. SG6, “Power Switching Equipment, Part 36, Outdoor Substations.”

NEMA Std. TTl-1977, “Tapered Tubular Steel Structures.”

RUS Bulletin 1728F-700, “RUS Specification for Wood Poles, Stubs and Anchor Logs”

RUS Bulletin 1728H-701, “RUS Specification for Wood Crossarms (Solid and Laminated), Transmission

Timbers and Pole Keys”

Steel Structures Painting Council Std. SSPC-PA 2, “Measurement of Dry Paint Thickness with Magnetic

Gages,” 1995.
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Steel Structures Painting Council Std. SSPC-PS 1.04, “Three-Coat Oil-Alky (Lead- and Chromate-Free)

Painting System for Galvanized or Non-Galvanized Steel (with Zinc Dust-Zinc Linseed Oil

Primer),” 1995.

Steel Structures Painting Council Std. SSPC-SP-1, “Solvent Cleaning,” 1995.

Steel Structures Painting Council Std. SSPC-SP-2, “Hand Tool Cleaning,” 1995.

Steel Structures Painting Council, Systems and Specifications, 7th ed.

U.S. Department of the Interior, “The BOCA Building Code.”

U.S. Department of the Interior, “Bureau of Reclamation Design Standard No. 10 Transmission

Structures.”

U.S. Department of the Interior, The Uniform Building Code.
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APPENDIX D

RISA-3D INPUT AND OUTPUT FOR A SIMPLE “T” STRUCTURE

RISA-3D (R) Version 3.01

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 ============================================================================

 Units............................. US Standard

 Steel Code........................ AISC 9th Edition ASD

 Allowable Stress Increase Factor.. 1.333

 Include Shear Deformation......... Yes

 Include Warping................... Yes

 No. of Sections for Member Calcs.. 5

 Do Redesign....................... Yes

 P-Delta Analysis Tolerance........ 0.50%

 Vertical Axis..................... Y

 ===========================< Joint Coordinates >============================

 Joint X Y Z Joint

 No Coordinate Coordinate Coordinate Temperature

 ------------------ft------------ft------------ft--------------øF------------

 1 0.000 0.000 0.000 70.00

 2 0.000 13.250 0.000 70.00

 3 -2.500 13.250 0.000 70.00

 4 2.500 13.250 0.000 70.00

 ==========================< Boundary Conditions >===========================

 Joint +--------- Translation --------+ +---------- Rotation ----------+

 No X Y Z Mx My Mz

 -----------K/in-------K/in-------K/in------K-ft/rad---K-ft/rad---K-ft/rad---

 1 Reaction Reaction Reaction Reaction Reaction Reaction

 ==========================< Materials (General) >===========================

 Material Young’s Shear Poisson’s Thermal Weight Yield

 Label Modulus Modulus Ratio Coef. Density Stress

 -------------Ksi----------Ksi----------------10^5øF----K/ft3-------Ksi------

 STL 29000.00 11154.00 0.3000 0.65000 0.490 36.00

 ================================< Sections >================================

 Section Database Material As As I I Torsion T

 Label Shape Label Area yy zz yy zz J C

 ------------------------------in^2--------------in^4------in^4------in^4----

 COL W8X28 STL 8.25 1.2 1.2 21.70 98.00 0.54

 BM1 W6X15 STL 4.43 1.2 1.2 9.32 29.10 0.10

 ================================< Members >=================================

 Member Joints x Axis Section End Releases Offsets Inactive?

 No I J K Rotate Set I: MMM J: MMM I-End J-End Label Length

 ---------------------------------xyzxyz-xyzxyz---in-----in-------------ft---

 1 1 2 COL 13.25

 2 2 3 BM1 2.50

 3 2 4 BM1 2.50
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 ==========================< AISC,NDS Parameters >===========================

 Section Length Lb-yy Lb-zz Lcomp K K Cmyy Cmzz Cb,B Sway

 Member Set le2 le1 le-bend yy zz CH y z

 ---------------ft------ft------ft------ft-----------------------------------

 1 COL 13.25 2.10 2.10

 2 BM1 2.50 2.10 2.10

 3 BM1 2.50 2.10 2.10

 ==========================< Basic Load Case Data >==========================

 BLC Basic Load Case Load Type Totals

 No. Description Nodal Point Dist. Surface

 ----------------------------------------------------------------------------

 1 Dead Load 5

 2 Extreme Ice 5 3

 3 Extreme Wind 8 1

 4 Extreme Wind Z 7 3

 5 Nesc Heavy in x 10 4

 6 Nesc Heavy in z 8 6

 7 Short Circuit 2

 =======================< Member Point Loads, BLC 1 >========================

 Joints

 Member I J Direction Magnitude Location

 -----------------------------------------K,K-ft-----------ft or %-----------

 2 2 3 Y -0.024 2.000

 3 2 4 Y -0.024 2.000

 2 2 3 Y -0.024 0.000

 1 1 2 Y -0.146 10.000

 1 1 2 My -0.146 10.000

 =======================< Member Point Loads, BLC 2 >========================

 Joints

 Member I J Direction Magnitude Location

 -----------------------------------------K,K-ft-----------ft or %-----------

 2 2 3 Y -0.037 2.000

 3 2 4 Y -0.037 2.000

 2 2 3 Y -0.037 0.000

 1 1 2 My -0.363 10.000

 1 1 2 Y -0.363 10.000

 ====================< Member Distributed Loads, BLC 2 >=====================

 Joints Load Pattern Pattern

 Member I J Label Multiplier

 ----------------------------------------------------------------------------

 2 2 3 BEMICE 1.0000

 3 2 4 BEMICE 1.0000

 1 1 2 COLICE 1.0000
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 =======================< Member Point Loads, BLC 3 >========================

 Joints

 Member I J Direction Magnitude Location

 -----------------------------------------K,K-ft-----------ft or %-----------

 1 1 2 X 0.039 10.000

 1 1 2 My -0.039 10.000

 2 2 3 X 0.055 2.000

 2 2 3 X 0.055 0.000

 3 2 4 X 0.055 2.000

 2 2 3 Mz 0.055 2.000

 2 2 3 Mz 0.055 0.000

 3 2 4 Mz -0.055 2.000

 ====================< Member Distributed Loads, BLC 3 >=====================

 Joints Load Pattern Pattern

 Member I J Label Multiplier

 ----------------------------------------------------------------------------

 1 1 2 COLWIND 1.0000

 =======================< Member Point Loads, BLC 4 >========================

 Joints

 Member I J Direction Magnitude Location

 -----------------------------------------K,K-ft-----------ft or %-----------

 2 2 3 Z -0.012 2.000

 2 2 3 Z -0.012 0.000

 3 2 4 Z -0.012 2.000

 2 2 3 My 0.007 2.000

 2 2 3 My 0.007 0.000

 3 2 4 My 0.007 2.000

 1 1 2 Z -0.039 10.000

 ====================< Member Distributed Loads, BLC 4 >=====================

 Joints Load Pattern Pattern

 Member I J Label Multiplier

 ----------------------------------------------------------------------------

 1 1 2 COLWNDZ 1.0000

 2 2 3 BEMWND1 1.0000

 3 2 4 BEMWND2 1.0000

 =======================< Member Point Loads, BLC 5 >========================

 Joints

 Member I J Direction Magnitude Location

 -----------------------------------------K,K-ft-----------ft or %-----------

 2 2 3 Y -0.010 2.000

 2 2 3 Y -0.010 0.000

 3 2 4 Y -0.010 2.000

 2 2 3 X 0.006 2.000

 2 2 3 X 0.006 0.000

 3 2 4 X 0.006 2.000

 1 1 2 X 0.004 10.000
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 =======================< Member Point Loads, BLC 5 >========================

 Joints

 Member I J Direction Magnitude Location

 -----------------------------------------K,K-ft-----------ft or %-----------

 1 1 2 Y -0.017 10.000

 1 1 2 My 0.017 10.000

 1 1 2 Mz 0.012 10.000

 ====================< Member Distributed Loads, BLC 5 >=====================

 Joints Load Pattern Pattern

 Member I J Label Multiplier

 ----------------------------------------------------------------------------

 1 1 2 COLNESX 1.0000

 1 1 2 COLNESC 1.0000

 2 2 3 BEMNESC 1.0000

 3 2 4 BEMNESC 1.0000

 =======================< Member Point Loads, BLC 6 >========================

 Joints

 Member I J Direction Magnitude Location

 ----------------------------------------K,K-ft-----------ft or %------------

 2 2 3 Z 0.004 2.000

 2 2 3 Z 0.004 0.000

 3 2 4 Z -0.004 2.000

 1 1 2 Y -0.017 10.000

 1 1 2 Z -0.022 10.000

 2 2 3 My -0.002 2.000

 2 2 3 My -0.002 0.000

 3 2 4 My -0.002 2.000

 ====================< Member Distributed Loads, BLC 6 >=====================

 Joints Load Pattern Pattern

 Member I J Label Multiplier

 ----------------------------------------------------------------------------

 2 2 3 BM1NESZ 1.0000

 3 2 4 BM2NESZ 1.0000

 1 1 2 COLNESZ 1.0000

 1 1 2 COLNESC 1.0000

 2 2 3 BEMNESC 1.0000

 3 2 4 BEMNESC 1.0000

 =======================< Member Point Loads, BLC 7 >========================

 Joints

 Member I J Direction Magnitude Location

 -------------------------------------K,K-ft-----------ft or %---------------

 2 2 3 X 0.009 2.000

 2 2 3 X -0.009 0.000
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 =============================< Load Patterns >==============================

 Pattern Magnitudes Locations

 Label Dir Start End Start End

 -----------------------K/ft,F----------K/ft,F----------ft or %-------ft or %---

 BEMICE Y -0.024 -0.024 0.000 2.500

 COLICE Y -0.027 -0.027 0.000 13.250

 COLWIND X 0.015 0.015 0.000 13.250

 COLWNDZ Z -0.018 -0.018 0.000 13.250

 BEMWND1 Z -0.013 -0.013 0.000 2.500

 BEMWND2 Z -0.013 -0.013 0.000 2.500

 COLNESX X 0.004 0.004 0.000 13.250

 BM1NESZ Z -0.004 -0.004 0.000 2.500

 BM2NESZ Z -0.004 -0.004 0.000 2.500

 COLNESZ Z -0.005 -0.005 0.000 13.250

 COLNESC Y -0.007 -0.007 0.000 13.250

 BEMNESC Y -0.007 -0.007 0.000 2.500

 ===========================< Load Combinations >============================

 RWPE

 No. Description BLC Fac BLC Fac BLC Fac BLC Fac BLC Fac SSdv

 ----------------------------------------------------------------------------

 1 DL + SC Y -1 1 1 7 1 y

 2 DL + EXT ICE + SC L01 1 2 1 y

 3 DL + EX WNDX + SC L01 1 3 1 y

 4 DL + EX WNDZ + SC L01 1 4 1 y

 5 DL + NESC X + SC L01 1 5 1 y

 6 DL + NESC Z + SC L01 1 6 1 y

 7

 =========================< Envelope Displacements >=========================

 +---------- Translation ---------+------------ Rotation -------------+

 Joint X lc Y lc Z lc Rx lc Ry lc Rz lc

 ----------in---------in---------in---------rad---------rad---------rad------

 1 U 0.000 3 0.000 1 0.000 5 0.00000 2 0.00000 4 0.00000 2

 L 0.000 2 0.000 2 0.000 4 0.00000 4 0.00000 5 0.00000 3

 2 U 0.136 3 0.000 1 0.115 2 0.00116 2 0.00351 4 0.00000 2

 L 0.000 2 -0.001 2 -0.426 4 -0.00374 4 0.00000 5 -0.00124 3

 3 U 0.136 3 0.037 3 0.115 2 0.00116 2 0.00349 4 0.00004 2

 L 0.000 2 -0.002 2 -0.321 4 -0.00374 4 0.00000 5 -0.00124 3

 4 U 0.136 3 -0.001 1 0.115 2 0.00116 2 0.00355 4 -0.00001 1

 L 0.000 2 -0.038 3 -0.532 4 -0.00374 4 0.00000 5 -0.00127 3

 ===========================< Envelope Reactions >===========================

 +------------- Forces ----------+------------- Moments -------------+

 Joint X lc Y lc Z lc Mx lc My lc Mz lc

 ---------K----------K----------K---------K-ft--------K-ft--------K-ft-------

 1 U 0.00 2 1.62 2 0.38 4 3.16 4 0.00 5 4.06 3

 L -0.40 3 0.67 1 0.00 5 -0.51 2 -0.02 4 0.00 2

 Tot: U 0.00 2 1.62 2 0.38 4

 L -0.40 3 0.67 1 0.00 5
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 ========================< Envelope Section Forces >=========================

 Member Shear Shear Moment Moment

 Sec Axial lc y-y lc z-z lc Torque lc y-y lc z-z lc

 --------------K----------K----------K--------K-ft-------K-ft-------K-ft-----

 1 1 U 1.62 2 0.40 3 0.38 4 0.00 1 0.51 2 4.06 3

 L 0.67 1 0.00 1 0.00 1 -0.02 4 -3.16 4 0.00 2

 2 U 1.43 2 0.35 3 0.32 4 0.00 1 0.51 2 2.81 3

 L 0.57 1 0.00 1 0.00 1 -0.02 4 -2.01 4 0.00 2

 3 U 1.25 2 0.30 3 0.26 4 0.00 1 0.51 2 1.72 3

 L 0.48 1 0.00 1 0.00 1 -0.02 4 -1.05 4 0.00 2

 4 U 1.07 2 0.25 3 0.20 4 0.00 1 0.51 2 0.80 3

 L 0.39 1 0.00 1 0.00 1 -0.02 4 -0.29 4 0.00 2

 5 U 0.38 2 0.16 3 0.10 4 0.00 1 0.00 3 0.16 3

 L 0.15 1 0.00 1 0.00 1 -0.02 4 0.00 4 0.00 2

 ----------------------------------------------------------------------------

 2 1 U 0.11 3 0.22 2 0.00 1 0.00 1 0.05 4 0.24 2

 L 0.00 1 0.09 1 -0.06 4 0.00 1 0.00 1 -0.01 3

 2 U 0.06 3 0.13 2 0.00 1 0.00 1 0.03 4 0.15 2

 L 0.01 1 0.05 1 -0.04 4 0.00 1 0.00 1 0.00 3

 3 U 0.06 3 0.11 2 0.00 1 0.00 1 0.01 4 0.08 2

 L 0.01 1 0.04 1 -0.03 4 0.00 1 0.00 1 -0.03 3

 4 U 0.06 3 0.09 2 0.00 6 0.00 1 0.00 6 0.02 2

 L 0.01 1 0.03 1 -0.02 4 0.00 1 0.00 4 -0.05 3

 5 U 0.00 1 0.00 1 0.00 1 0.00 1 0.00 1 0.00 2

 L 0.00 1 0.00 1 0.00 1 0.00 1 0.00 1 0.00 1

 ----------------------------------------------------------------------------

 3 1 U 0.00 1 0.16 2 0.04 4 0.00 1 0.00 1 0.24 2

 L -0.05 3 0.06 1 0.00 1 0.00 1 -0.07 4 0.10 1

 2 U 0.00 1 0.13 2 0.04 4 0.00 1 0.00 1 0.15 2

 L -0.05 3 0.05 1 0.00 1 0.00 1 -0.05 4 0.06 1

 3 U 0.00 1 0.11 2 0.03 4 0.00 1 0.00 1 0.08 3

 L -0.05 3 0.04 1 0.00 1 0.00 1 -0.03 4 0.03 1

 4 U 0.00 1 0.09 2 0.02 4 0.00 1 0.00 6 0.06 3

 L -0.05 3 0.03 1 0.00 1 0.00 1 -0.01 4 0.01 1

 5 U 0.00 1 0.00 1 0.00 1 0.00 1 0.00 4 0.00 2

 L 0.00 1 0.00 1 0.00 1 0.00 1 0.00 1 0.00 5

 ----------------------------------------------------------------------------

 ======================< Envelope Section Deflections >======================

 +--------- Translation ---------+ Defls as L/n Ratios

 Memb Sec x lc y lc z lc Rot x lc L/n(y) lc L/n(z) lc

 -------------in---------in---------in--------rad--------rad--------rad------

 1 1 U 0.000 1 0.000 1 0.000 1 0.00000 1 NC 1 NC 1

 L 0.000 1 0.000 1 0.000 1 0.00000 1 NC 1 NC 1

 2 U 0.000 1 0.000 1 0.008 2 0.00088 4 NC 1 NC 2

 L 0.000 2 -0.013 3 -0.042 4 0.00000 1 NC 3 3807.3 4

 3 U 0.000 1 0.000 1 0.031 2 0.00176 4 NC 1 5173.7 2

 L 0.000 2 -0.044 3 -0.144 4 0.00000 1 3603.9 3 1100.4 4

 4 U 0.000 1 0.000 2 0.069 2 0.00264 4 NC 2 2300.9 2

 L -0.001 2 -0.087 3 -0.279 4 0.00000 1 1824.6 3 569.2 4
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 ======================< Envelope Section Deflections >======================

 +--------- Translation ---------+ Defls as L/n Ratios

 Memb Sec x lc y lc z lc Rot x lc L/n(y) lc L/n(z) lc

 -------------in---------in---------in--------rad--------rad--------rad------

 5 U 0.000 1 0.000 2 0.115 2 0.00351 4 NC 2 1377.5 2

 L -0.001 2 -0.136 3 -0.426 4 0.00000 1 1171.6 3 373.1 4

 ----------------------------------------------------------------------------

 2 1 U 0.000 2 0.000 1 0.426 4 0.00374 4 NC 1 286.1 4

 L -0.136 3 -0.001 2 -0.115 2 -0.00116 2 NC 2 NC 2

 2 U 0.000 2 0.009 3 0.400 4 0.00374 4 3238.5 3 381.8 4

 L -0.136 3 -0.001 2 -0.115 2 -0.00116 2 NC 2 NC 2

 3 U 0.000 2 0.018 3 0.374 4 0.00374 4 1619.6 3 573.0 4

 L -0.136 3 -0.001 2 -0.115 2 -0.00116 2 NC 2 NC 2

 4 U 0.000 2 0.028 3 0.347 4 0.00374 4 1079.0 3 1146.0 4

 L -0.136 3 -0.001 2 -0.115 2 -0.00116 2 NC 2 NC 2

 5 U 0.000 2 0.037 3 0.321 4 0.00374 4 808.5 3 NC 4

 L -0.136 3 -0.002 2 -0.115 2 -0.00116 2 NC 2 NC 2

 ----------------------------------------------------------------------------

 3 1 U 0.136 3 0.000 1 0.115 2 0.00116 2 NC 1 NC 2

 L 0.000 2 -0.001 2 -0.426 4 -0.00374 4 NC 2 NC 4

 2 U 0.136 3 0.000 1 0.115 2 0.00116 2 NC 1 NC 2

 L 0.000 2 -0.010 3 -0.453 4 -0.00374 4 3199.3 3 1134.4 4

 3 U 0.136 3 0.000 1 0.115 2 0.00116 2 NC 1 NC 2

 L 0.000 2 -0.019 3 -0.479 4 -0.00374 4 1591.9 3 566.0 4 

 4 U 0.136 3 -0.001 1 0.115 2 0.00116 2 NC 1 NC 2

 L 0.000 2 -0.029 3 -0.506 4 -0.00374 4 1057.0 3 376.7 4

 5 U 0.136 3 -0.001 1 0.115 2 0.00116 2 NC 1 NC 2

 L 0.000 2 -0.038 3 -0.532 4 -0.00374 4 790.4 3 282.2 4

 ----------------------------------------------------------------------------

 =======================< Envelope AISC Unity Checks >=======================

 Unity Shear Fb Fb Cm Cm ASD

 Memb Chk Loc lc Chk Loc lc Fa yy zz Cb yy zz Eqn

 -----------------------------------Ksi----Ksi----Ksi------------------------

 1 0.229 1 4 0.015 3 z 4 3.52 27.00 21.60 1.00 0.85 0.60 H1-2

 2 0.013 1 2 0.013 1 y 2 18.91 26.26 23.46 1.00 0.60 0.85 H1-2

 3 0.016 1 4 0.010 1 y 2 18.91 26.26 23.46 1.00 0.85 0.85 H1-2
Bulletin 1724E-300

Page 465

CHAPTER 8

FOUNDATIONS

8.1 GENERAL

Foundation design primarily depends on the in-place density and strength/strain properties of the soil on

or in which foundations are located. The heterogeneous characteristics of soils or their localized

variability make foundation design a much less exacting engineering problem than structural design or

some facets of electrical design, but the inexactness of soil mechanics need not be a reason for

ultraconservatism and costly foundations. Further, with the enhancements of convenient computer

programs, tedious repetition of design practices for foundation design has been reduced. While this

chapter is intended as a general guide, it cannot serve as a guarantee against foundation problems.

A thorough knowledge of geotechnical subsurface engineering parameters is essential to providing a

reliable and cost-effective foundation design. Geotechnical engineering or soil analysis is beyond the

scope of this document and generally requires the services of a geotechnical engineer to prepare sitespecific recommendations. When designing foundations, it is important to address the following design

issues:

• The allowable load-bearing capacity of the subsurface materials

• The allowable deformations permitted upon the structure/foundation under loading

In addition to site-specific borings and laboratory testing, additional data may be gathered pertinent to the

site through reference to state or federal geologic mapping, aerial photos, Natural Resource Conservation

Service (formerly the Soil Conservation Service) mapping, and other hydrological references. A number

of federal and state agencies frequently have available information that can be consulted and will provide

either regional or localized data to supplement a site subsurface investigation.

8.2 SOIL INFORMATION

8.2.1 General

A subsurface investigation should be conducted for each substation. Temporary installations and small

distribution substations may only require a minimal amount of information. At these locations augered

probe borings, in situ quasi-static cone penetrations (ASTM D3441), vane shear tests (ASTM D2573), or

the pressure meter (ASTM D4719) can be used to provide an indication of the soil’s engineering

characteristics.

Soil probes or borings should be taken primarily at critical foundations. These normally are for line

support structures (i.e., deadends) and transformers. The number of borings may vary from three at small

substations to six or ten at larger substations. The depth of borings should be about 10 meters (30 feet)

below the final grade of the substation yard, but may vary dependent upon:

1. Intensity of structural loads

2. Softness or wetness of subsurface soils

3. Depth of groundwater level

A sample specification for procurement of soil borings is included as an Appendix E to this chapter.
Bulletin 1724E-300

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8.2.2 Soil Classification

Because of design considerations, the geotechnical engineer will typically determine whether to design

the foundations as if the soil behaves as a cohesive (fine-grained clay-like) soil or as a granular or

cohesionless (coarse-grained sand-like) soil. The description of the material noted on the soil boring log

should be described in accordance with the Unified Soil Classification System (ASTM D2487 and

D2488). (See Table 6-2 in Chapter 6.)

Material described as “sandy clay” can, for example, be assumed to behave predominately as cohesive

material, whereas “clayey sand” will probably behave as granular material. The relative quantities of

cohesive and granular materials can appreciably affect the soil properties and cause concern. Therefore,

when in doubt, design the foundations both ways and use the most conservative design.

To assist with the visual classification of soil types, specific index classification tests can be performed.

Typical index classification tests for cohesionless and cohesive soils are as follows:

Cohesionless

Grain Size Sieve Analysis ASTM D422

Moisture Content ASTM D2216

Specific Gravity ASTM D854

Cohesive

Atterberg Limits ASTM D4318

Moisture Content ASTM D2216

Unit Weight ASTM D2216

Specific Gravity ASTM D854

Hydrometer ASTM D422

Index tests provide data that can frequently be correlated with other engineering characteristics of the

soils such as strength, swell potential, collapse potential, consolidation, and degree of compaction.

Although index tests should not be viewed as a total replacement to undisturbed engineering tests, they

frequently can be used to supplement an investigation program and confirm either consistency or

variability at site.

Specific references are available in research that relate index properties to engineering properties; these

should be reviewed by an individual familiar with geotechnical engineering design who understands their

limitations and appropriateness for use. Typically, it is not recommended to simply utilize presumptive

engineering properties from tables or texts that rely on standard penetration tests, visual classifications,

and limited index tests alone, particularly for cohesive soils where greater variability in strength and

deformation may occur locally. Presumptive values for allowable bearing pressures on soil or rock

should be used only as a means of guidance or for preliminary or temporary design. Further, the degree

of disturbance to soil samples, whether standard penetration test samples or relatively undisturbed

samples, have to be kept to a minimum prior to laboratory testing through the use of appropriate drilling,

sampling, and transportation methods.

8.2.3 Bearing Values

Bearing values or engineering parameters developed from laboratory tests upon cohesive soils should be

obtained from relatively undisturbed samples in accordance with “Practice for Thin-Walled Tube
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Geotechnical Sampling of Soils,” ASTM D1587, or “Practice for Ring-Lined Barrel Sampling of Soils,”

ASTM D3550.

Engineering parameters for granular soils can generally be estimated reliably by correlations with

standard penetration blow counts. The parameter obtained is usually the internal friction angle (φ).

Unconfined compressive strengths for cohesive or clay-like soils are best determined using “Test Method

for Unconfined Compressive Strength of Soil” (ASTM D2166), although rough correlations relative to

standard penetration tests have been developed.

In situ strengths derived from the quasi-static cone penetrometer (ASTM D3441), vane shear

(ASTM D2573), or pressuremeter (ASTM D4719) are frequently more reliable, particularly in very soft

soils, because of their minimization of sample disturbance and testing of the soils in place.

Rock coring to obtain sample recovery, Rock Quality Designation (RQD), and unconfined strengths may

be required for sites with anticipated rock formations. It is also important to be familiar with local

engineering characteristics of not only the individual rock formations present, but also their global or rock

mass properties. Give special design consideration to swelling shales, steeply dipping rock, highly

weathered or decomposed rock units, fractured or jointed rock, or clay or bentonite seamed rock units.

These conditions may impact both the strength and deformation performance of structures founded in or

upon rock.

8.2.4 Groundwater Level

The elevation of the groundwater level is important in foundation design for several reasons. Open-cut

excavations below it within permeable stratas require dewatering and increased costs. The water level

also has considerable influence on the bearing capacity and total settlement in granular soils. The bearing

capacity of a spread footing in granular soil is derived from the density of the soil below the footing and

the density of the soil surrounding the footing (backfill or surcharge). A rise of the water level above a

depth greater than the width of the footing up to the top of the surcharge in effect reduces the effective

overburden pressures within the sand to roughly half their original values, and further reduces the

stiffness or strain carrying capacity of the granular soils. Therefore, the footing pressure that is expected

to produce a 1-inch total settlement when the water level is at the surface is only about half that required

to produce a 1-inch total settlement when the water level is at or below a depth equal to the footing width

below the base of the footing.

The effect of the water level is to reduce the effective overburden pressure or density of the granular soil

because of buoyancy. The submerged density of granular soil is about half of the moist or dry density. If

the water level is at or exceeds a depth equal to the footing width below the base of the footing, the

bearing capacity is not affected. If the water level is at the bottom of the footing or may rise to the ground

surface, the portion of bearing capacity obtained by the density of soil below the footing is reduced in

half. If the water level is at the top of the backfill, the portion of bearing capacity obtained by the density

of the surcharge is also reduced in half.

8.2.5 Differential Settlement

Minor differential settlement between foundations in substations is generally acceptable. However, there

are certain soils and conditions that have to be carefully reviewed and avoided if possible. Silts and silty

sands are usually problem soils, both from strength relationships and degree of compaction. Carefully

examine weak strata of soil under a thin layer of dense or good soil and take them into consideration

regarding settlement. Organic or swamp-like soils, or uncompacted fills, pose a risk to differential long-
Bulletin 1724E-300

Page 468

term settlement to structures. Soils that may expand, collapse, or disperse upon wetting require special

attention for design by a geotechnical engineer.

8.2.6 Chemical Tests

Soils may impact foundations and other buried systems as a result of chemical attack on concrete,

corrosion of steel, and other detrimental weathering. Consult a corrosion specialist or engineer familiar

with these chemical tests to determine the appropriate cement type based on prevailing soluable sulfate

and chloride ion concentrations within the soil or groundwater. Resistivity of the soil, pH, sulfides,

Redox readings, and nitrates may also have detrimental effects on concrete, steel, or grounded structures.

These conditions require localized testing and design.

8.2.7 Seismic Evaluation

Seismic evaluation of substation sites is currently beyond the scope of this document, but should be

reviewed locally by a geotechnical engineer, and geologist, where required. Delineating the location of

faults and surface disruptions, and the potential for sand boils, soil flows, slope slides, and liquefiable

soils, is essential to designing foundations that remain stable under extreme seismic events. If

liquefaction is determined to be likely at a site under certain seismic events, then design of the

foundations to extend beyond such zones or mitigation measures to improve the soils will need to be

pursued in final design. Hand calculation techniques or commercially available computer programs

performed by a geotechnical engineer can evaluate liquefaction potential, based on probable earthquake

criteria.

8.3 FOUNDATION TYPES

The various types of foundations for substation structures and equipment include drilled shafts (augered

piers), spread footings, piles, slabs on grade, rock anchors, and direct embedment for wood or concrete

poles.

8.3.1 Drilled Shafts (Piers)

The drilled shaft is constructed by augering, drilling, or coring a hole in the ground, placing reinforcing

steel, and filling with concrete. The anchor bolts may be cast in the shaft at this time or set in a cap

constructed at some later time. Drilled shaft construction and design has been developed and researched

by the Association of Drilled Shaft Contractors (ADSC) and the American Concrete Institute (ACI), each

of which has developed typical standard specifications for their construction. Further, design and

construction procedures are documented through extensive research on behalf of the Federal Highway

Administration (FHWA), U.S. Department of Transportation, in the Drilled Shaft Manual (Publication

No. FHWA Implementation Package 77-21) and Drilled Shafts (Publication No. FHWA-HI-88-042).

When there is a sufficient quantity of foundations, the drilled shaft foundations are usually more

economical than other types because of the “assembly line” installation procedure. Drilled shafts are

most economical when soil conditions are not wet and sandy, although, with care and quality control

oversight during construction, casings, bentonite slurries, and polymer muds are currently available to

promote their construction.

If wet and sandy soil is below a level where a spread footing would bear, the spread footing should be

evaluated and may be selected. However, if wet and sandy conditions also exist above the spread footing

level, consider the drilled shaft, allowing extra costs for encasement. This design may be more
Bulletin 1724E-300

Page 469

economical than attempting to install a spread foundation in wet, sandy soil, requiring either dewatering

to stabilize the excavation or pumped concrete below water.

Drilled shafts are best suited to resist overturning shears and moments. Uplift and compressive forces are

also adequately resisted by drilled shafts. Where soils permit belling of the shaft, additional uplift or

compressive capacity is often gained economically.

Common sizes for substation foundations range from 0.61 meter (24 inches) to l.52 meters (60 inches) in

diameter, in 150-mm (6-inch) increments. Drilled shafts above 2.13 meters (84 inches) in diameter are

typically installed in 300-mm (12-inch) increments with a maximum diameter of 3.05 meters (120 inches)

available for extreme substation applications.

The engineer should attempt to utilize the same shaft diameter for as many foundations as practical.

Belling of the shaft is less frequently performed for substation foundations, but has cost advantages when

permissible.

For most substation equipment support structures and line support structures, the foundations are required

to resist moderate shear forces and overturning moments. For A-frame and lattice-type line support

structures, shear, uplift, and compression are typical design loads. Drilled shafts also provide improved

performance against differential settlement for critical transformer structures and have been used to

provide support against overturning loads resulting from wind or seismic design conditions.

8.3.2 Drilled Shaft Design

Drilled shaft foundations derive their support to carry loads based on the shaft’s shape (straight versus

belled), soil/rock stratification, groundwater level, and applied loads. Generally, compressive loads are

carried by a combination of skin friction along the shaft’s perimeter and end bearing at the base. In cases

where shafts bear upon or in rock, the overlying soil skin friction is typically discounted for design.

Uplift loads are carried as skin friction alone for straight shafts. Shafts with bells require special review

as to their capacity and the load transference mechanism based upon soil strata types and depth-todiameter ratios of shaft and bell embedment. Lateral loads (shear and/or moment) are carried by the

lateral resistance of soil/rock against the shaft’s cross section.

The spacing of shafts for adjacent structures, commonly referred to as group action, should be evaluated

to prevent or minimize stress overlap from skin friction or lateral stresses. A common rule of thumb is to

maintain a minimum shaft spacing (centerline to centerline) of not less than three times the diameter,

although selected research has indicated that some soil types may require a greater shaft spacing.

Typically, compression and uplift loads are designed separate from lateral design analyses. Conventional

factors of safety are applied to compression and uplift soil resistance to account for potential variability of

subsurface conditions. Depending on the method of lateral load analysis used for design, the lateral

design may or may not use factors of safety. Methods employed that evaluate shaft deflection and

rotation performance typically do not use factors of safety since they are determining the predicted

load/deformation characteristics of the drilled shafts under the design loading.

Specific techniques for design of shafts have been documented quite thoroughly by others. One useful

source in performing final design is IEEE Std. 691, “IEEE Trial-Use Guide for Transmission Structure

Foundation Design,” which was jointly authored by the Institute of Electrical and Electronics Engineers

and the American Society of Civil Engineers (ASCE).
Bulletin 1724E-300

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For purposes of lateral design of drilled shaft foundations, several techniques exist to evaluate shaft

performance. With the advent of computers and the ability to evaluate multiple length and diameter shaft

combinations readily, lateral analysis of shafts has been performed by methods employing computer

stress/strain relationships rather than the older rough calculations by hand using ultimate strength of a

passive pressure wedge.

The design of drilled shafts for lateral loads should account for the effects of soil/rock–structure

interaction between shaft and subsurface stratas to account for deflection and rotation of the shafts. Final

design methods employing this conventional process are described under Method A presented below. In

1995 the Rural Utilities Service generated a Design Guide, RUS Bulletin 1724E-205, “Embedment

Depths for Concrete and Steel Poles,” for preliminary selection of embedment depths for concrete and

steel poles. Selected literature from this document is referenced in RUS Bulletin 1724E-205 is briefly

described under Method B presented below. Previous procedures identified in the 1978 predecessor

edition of this manual are again provided and described under Method C. It is recommended that the

Method C procedures for evaluating the ultimate capacity and deflection, based on hand calculation

procedures (e.g., Czerniak 1957; Broms 1964) be used primarily for preliminary design or cost estimating

purposes. Along with the earlier mentioned FHWA publications and IEEE Std. 691, government

agencies including the American Association of State Highway and Transportation Officials require

computer-modeled finite difference procedures like those described in Method A.

8.3.2.1 Method A—Lateral Drilled Shaft Design (Computer-Modeled Soil Interaction Curves):

Drilled shaft response is dependent upon the applied load, the soil/rock stratigraphy (including

groundwater level), and the dimensional and physical features of the drilled shaft. Under applied load,

soil–structure interaction behaves in either a linear-elastic, elastic-plastic, or ultimate-plastic state,

depending on the soil subgrade modulus. The resulting load-displacement relationship has been described

by Reese and O’Neill in FHWA publications as nonlinear subgrade modulus P-Y curves. A similar

design/analysis model has been prepared and developed by EPRI (Project RP-1280-1).

The use of P-Y curves describing the relationship between lateral pressure P and lateral displacement Y at

individual stations along the length of the shaft permits the computer program to solve for deflected

shapes of the shaft, as developed for the specific stratigraphic soils present. It is possible to assign rock

fixity with Reese’s program at any point along the shaft and to account for additional rotational restraints,

such as grade beams or slab inter-ties.

Output from the computer analysis includes deflections, rotations, internal moments, internal shears, and

soil reactions along the entire shaft length. Moments and shears generated by the program are used by

structural engineers to design the amount and spacing of longitudinal and tie steel. The program further

permits evaluation of shaft performance under the cracked section analysis, resulting in a more accurate

representation of shaft and structure movement under load.

Reese’s fundamental theoretical principles were documented in 1977 and 1988. The computer program

(COM624) was originally developed for the FHWA and is currently available through the Center for

Microcomputers in Transportation, McTRANS Center, as sponsored by the University of Florida at

Gainesville. Other comparable commercial versions of this public domain program are also available for

purchase.

8.3.2.2 Method B—Lateral Shaft Resistance Design (RUS-Hansen Approach): With the

increasing use of both concrete and steel (light-duty) poles as replacements for wood poles in selected

instances, RUS documented a method of evaluating pole embedment using an earlier referenced approach

prepared by Hansen in 1961 for stratified soils.
Bulletin 1724E-300

Page 471

The design analogies applied to direct-embedded poles can be further extended through Hansen’s

methodology to drilled shafts installed in stratified soils. As noted in RUS Bulletin 1724E-205, “The

engineering information in this bulletin is for use in preliminary selection of embedment depths for steel

and concrete transmission poles sustaining relatively large overturning moments.” Bulletin 1724E-205

further notes the limitations of this method due to the proposed national scope of use and variations in

localized performance.

RUS Bulletin 1724E-205 describes comparisons performed between the methods of Hansen (1961),

Broms (1964), RUS Bulletin 1724E-200, “Design Manual for High Voltage Transmission Lines.”

Davisson and Prakash (1963), and Naik and Peyrot (1980).

Drilled shafts designed previously by the Broms method for line support structures (as further described

in Method C from the 1978 REA Design Guide for Rural Substations) may be alternatively designed for

stratified soils with the Hansen method outlined in RUS Bulletin 1724E-205, “Embedment Depths for

Concrete and Steel Poles.”

8.3.2.3 Method C—Lateral Drilled Shaft Design (Equipment Support Structures) [Reprinted

from 1978 RUS Manual]: Equipment support structures designed by the working stress method having

overturning moments at the column bases may be easily designed by a method developed by E. Czerniak

and published in the Journal of the Structural Division of the Proceedings of the American Society of

Civil Engineers in March 1957.

Convenient nomographs and soil values make the tedious formulas unnecessary. Some formulas are

presented here for purposes of illustration and as an aid in design.

Equation 8-1

Where:

L = Embedment length in meters (feet)

Ho = Lateral force per meter (foot) of pier diameter, in N/m (lbs/ft)

Mo = Moment per meter (foot) of pier diameter, applied at the resisting surface, in m-N/m (ft-lbs/ft)

R = Allowable lateral soil resistance, in newtons per square meter per meter of depth

(pounds per square foot per foot of depth)

Lateral soil pressure (R) values for design are given in Table 8-1.

The maximum bending moment in the shaft is obtained from Equation 8-2:

Equation 8-2

Where:

D = Shaft diameter, in meters (feet)

CM = Moment coefficient

O for round piers

R

M

R

H L

L

o o − 14.14 − 18.85 =

3

M MAX = C M Ho LD
Bulletin 1724E-300

Page 472

Table 8-1: Recommended Lateral Soil Pressure (R).

Ref. E. Czerniak, Journal of the Structural Division of the Proceedings of the American Society of Civil

Engineers, March 1957. Reproduced with permission of the American Society of Civil Engineers.

Material Value

PSF/FT N/m2/m

Rock in Natural Beds – Limited by the Stress in the Pier

Medium Hard Caliche 500 78,500

Fine Caliche with Sand Layers 400 62,800

Compact Well-Graded Gravel 400 62,800

Hard Dense Clay 400 62,800

Compact Coarse Sand 350 55,000

Compact Coarse and Fine Sand 300 47,100

Medium Stiff Clay 300 47,100

Compact Fine Sand 250 39,300

Ordinary Silt 200 31,400

Sandy Clay 200 31,400

Adobe 200 31,400

Compact Inorganic Sand and Silt Mixtures 200 31,400

Soft Clay 100 15,700

Loose Organic Sand and Silt Mixtures and Muck or Bay Mud 0 0

(Newtons per Square Meter per Meter Depth)

(Pounds per Square Foot per Foot Depth)

CM, the moment coefficient, can be calculated from Equation 8-3 and Figure 8-1, or the maximum value

can be obtained from Table 8-2.

Equation 8-3

Where:

X = Distance from supporting surface to point of maximum bending moment (for the force

diagram shown X = 0.35 L ±)

Table 8-2: Moment Coefficients

E/L 0 0.25 0.5 0.75 1.0 1.25 1.5 1.75 2.0

CM 0.26 0.48 0.70 0.92 1.16 1.40 1.64 1.88 2.12

A drilled shaft foundation design example is illustrated in Figure 8-2 for a bus support structure.

Ht = 2.27 kN

Mt = 12.42 kNm

assume R = 39.3 kN/m2/m

D = 0.61 m

3 4

M

L

X

2

L

3E

L

X

3

L

4E

L

X

L

E

C 























 + +























 − +











= +

o

o

H

M

E =
Bulletin 1724E-300

Page 473

Figure 8-1: Drilled Shaft Force and Moment Diagrams

Figure 8-2: Drilled Shaft Elevation—Example
Bulletin 1724E-300

Page 474

L = 2.37 meters; say 2.4 meters

For this foundation use six 15.9 mm φ bars at equal spacing for reinforcement; see Tables 8-3 through

8-6. Use 9.55 mm φ bars for ties.

Table 8-3: Maximum Moment in kN-m for Augered Piers with 6 Straight Bars

Diameter of

Augered Pier 6-15.9mm 6-19.1mm 6-22.2mm 6-25.4mm

 30.5cm Φ 7.8 11.1 15.0 19.9

 45.7cm Φ 14.6 20.7 28.2 37.1

 61.0cm Φ 21.4 30.3 41.4 54.4

 76.2cm Φ 28.1 39.9 54.5 71.7

 91.4cm Φ 34.8 49.5 67.5 88.9

106.7cm Φ 41.6 59.1 80.7 106.2

121.9cm Φ 48.4 68.7 93.8 123.5

(Fy = 27.6 kNcm2, fC’ = 2060 N/cm2

(Based upon simplified working stress assumptions)

( )

m

20.92 kNm

.61m

12.42 kNm .15 m 2.27 kN

D

M

M t

o =

+

= =

m

kN 3.72

.61m

2.27 kN

D

H

H

t

o = = =

E 5.62 m

3.72

20.92

= =

14.14 18.85 0

3

− − =

R

M

R

H L

L

o o

( ) ( )

0

39.3

20.92 18.85

39.3

3.72 14.14 3

− − =

L

L

2.3

2.4

5.62

= =

L

E

(0.24) 2.12 2.41

25

30 interpolating = + = CM

Mmax = CM HoLD = 2.41 (3.72)2.4(0.61) = 13.1 kNm
Bulletin 1724E-300

Page 475

Table 8-4: Maximum Moment in kN-m for Augered Piers with 8 Straight Bars

Diameter of

Augered Pier 8-15.9mm 8-19.1mm 8-22.2mm 8-25.4mm

 30.5cm Φ 11.4 16.3 22.1 29.2

 45.7cm Φ 21.3 30.2 41.2 54.2

 61.0cm Φ 31.0 44.2 60.2 79.3

 76.2cm Φ 40.9 58.0 79.2 104.3

 91.4cm Φ 50.7 72.0 98.2 129.3

106.7cm Φ 60.6 86.0 117.3 154.4

121.9cm Φ 70.4 99.9 136.3 179.4

(Fy = 27.6 kN/cm2, fC’ = 2060 N/cm2

(Based upon simplified working stress assumptions)

Table 8-5: Maximum Moment in Ft-KIPS for Augered Piers with 6 Straight Bars

Diameter of

Augered Pier 6 - #5 6 - #6 6 - #7 6 - #8

12” Φ 5.75 8.2 11.1 14.7

18” Φ 10.8 15.3 20.8 27.4

24” Φ 15.8 22.4 30.5 40.1

30” Φ 20.7 29.4 40.2 52.9

36” Φ 25.7 36.5 49.8 65.6

42” Φ 30.7 43.6 59.5 78.3

48” Φ 35.7 50.7 69.2 91.1

(Fy = 40 KSI, fC’ = 3000 PSI)

(Based upon simplified working stress assumptions)

Table 8-6: Maximum Moment in Ft-KIPS for Augered Piers with 8 Straight Bars

Diameter of

Augered Pier 8 - #5 8 - #6 8 - #7 8 - #8

12” Φ 8.4 12.0 16.3 21.5

18” Φ 15.7 22.3 30.4 40.0

24” Φ 22.9 32.6 44.4 58.5

30” Φ 30.2 42.8 58.4 76.9

36” Φ 37.4 53.1 72.4 95.4

42” Φ 44.7 63.4 86.5 113.9

48” Φ 51.9 73.7 100.5 132.3

(Fy = 40 KSI, fC’ = 3000 PSI)

(Based upon simplified working stress assumptions)

8.3.3 Drilled Shaft Design (Line Support Structure)

For pole-type line support structure foundations, a different method of foundation design is employed.

These structures are designed on the basis of yield stress, and appropriate overload factors are applied to

the structure loads. To complement these loadings, a foundation design is used utilizing the ultimate

strength of the soil. A very satisfactory method is illustrated, developed by Teng and Associates and

based on the theory presented by B.B. Broms in the Journal of the Soil Mechanics and Foundation

Division of the Proceedings of ASCE (March 1964 and May 1964).
Bulletin 1724E-300

Page 476

Figure 8-3: Drilled Shaft Section

Some of this information is presented here as an aid in design:

kp = Coefficient of passive earth pressure

= Tan2(45 + φ/2)

φ = Angle of internal friction of soil ≅ 28.5° + N/4

γ = Effective unit weight of soil, in kg/m3 (pcf)

c = Cohesive strength of soil, 1⁄2 unconfined compressive strength (qu), in N/m2 (psf)

N = Number of blows per foot from standard penetration test

H = M/Q

qu = Unconfined compressive strength ≅ N/4

q =

9cD

Q

For a drilled shaft foundation in cohesive soil use Equations 8-4 and 8-5:

Equation 8-4

Equation 8-5

L =1.5D + q [ 1+ 2 + (4H +6D)/q ]

@1.5D q below top of foundation

18cD

Q M M 1.5 QD

2

max = + + +
Bulletin 1724E-300

Page 477

Figure 8-4: Drilled Shaft Elevation—General

For a drilled shaft foundation in granular soil, use Equations 8-6, 8-7, 8-8, and 8-9:

Equation 8-6

Equation 8-7

Equation 8-8

Equation 8-9

Utilize standard design procedures for determining the required area of reinforcing steel.

(Metric )

k D

M

k D

QL

L

p p

0

3 200 200

− − =

g g

(English)

k D

M

k D

QL L

p p

0

3 2 2

− − =

g g

(Metric)

0.010k D

Q @

0.010k D

0.545Q Q M M 0.817

p p

max bending

belowgrade

γ γ

= +

(English)

k D

Q @

k D

0.545Q Q

M M 0.817

p p

max bending

belowgrade

γ γ

= +
Bulletin 1724E-300

Page 478

A foundation design using Brom’s Theory for granular soil is illustrated below:

8.3.3.1 Design Example 8-1

Given:

Q = 47.6 kN

M = 535 kNm

γ = 1762 kg/m3

φ = 28.5 + 26/4 = 35°

D = 1.22 m

N = 26 blows/.3048 m

tan (45 35 / 2) 3.69 2k p = ° + ° =

L = 2.56 m + 0.15 m for reveal

L = 2.7 m

8.3.4 Compression and Uplift Capacity (Drilled Shafts)

When designing drilled shaft foundations for loads that consist of compression or uplift, the type of soil

(cohesive or granular) will govern the design philosophy employed.

As referenced in IEEE Std. 691, drilled shaft resistance is typically derived from the strength relationship

of the cohesive or granular soil stratigraphy. Further, the depth of water will impact these design

capacities.

8.3.4.1 Compression Capacity: Axial compressive loads applied to a drilled shaft are resisted by both

skin friction and end bearing. Initially, as loads are applied, they are generally transferred as skin friction

to the soil with increasing depth, and then redistributed from the top of the shaft down as loads increase.

With increased axial compressive loads, the relative percentage of load carried at the base as end bearing

increases. This load transfer mechanism is impacted by such factors as type of soil, depth of strata along

shaft, base support material, water level, in situ stresses, construction methods employed, and relative size

and shape of the shaft.

An extensive amount of research has been performed on drilled shafts utilizing full-scale load tests to

analyze the soil/structure interaction. Although numerous approaches have been documented, the

generally accepted procedure for straight shafts in cohesive soils is described as the “Alpha” method and

in cohesionless soils as the “KO” method.

( )

( )

( ( ))

( )

0

3.69 1762 1.22

200 535 0.15 47.6

3.69 1762 1.22

200 47.6 L

L

3 =

+

− −

( )

( )

( ) ( )

562 kNm

0.010 3.69 1762 1.22

0.545 47.6 47.6 Mmax bending = 535 + 0.15 47.6 + =

( ) ( )

0.63 m below grade

0.010 3.69 1762 1.22

47.6 @ 0.817 =
Bulletin 1724E-300

Page 479

8.3.4.1.1 Cohesive (Undrained) Soil (“Alpha” Method)

Equation 8-10

Where:

D = Diameter of shaft, in m (ft)

DB = Diameter of shaft base, in m (ft)

á = Alpha, shear strength reduction factor

c = Cohesion, undrained shear strength (1⁄2 unconfined compressive strength), in N/m2 (psf)

Li = Increments of shaft in different stratas, in m (ft)

H = Total length of shaft, in m (ft)

Nc = Bearing capacity factor for deep foundations

F.S. = Factor of safety

For drilled shaft foundations where the depth-to-diameter ratio exceeds approximately 4.0, the value for

Nc for deep foundations may be assumed as equal to 9.0 according to Adams and Radhakrishna (1975);

Meyerhof (1951); and Woodward, Gardner, and Greer (1972). At depth-to-diameter ratios less than 4.0,

the Nc factor has to be adjusted toward shallow foundation design in accordance with Vesic, but will not

be less than 5.14 according to Terzaghi (1943).

The Alpha factor has been developed from numerous studies by researchers and is generally considered to

be similar to Figure 8-5 for drilled shafts by Kulhawy and Jackson (dependent upon shear strength).

Because of the variability of soils, even with a comprehensive subsurface investigation, a factor of safety

in compression of 2.0 to 3.0 is typically used for cohesive soils. A higher factor of safety in cohesive

soils is justified to recognize the more long-term tendency of cohesive soils to experience settlement.

4 . .

Equation 8- 12

. .

Equation 8- 11

2

0

F S

D N c

Q

F S

cL

Q D

Q Q Q

B c

EB

H

i

SF

T SF EB

i

p

a

p

=

=

= +

∑=
Bulletin 1724E-300

Page 480

Figure 8-5: á Function for Drilled Shafts. Ref. Kulhawy and Jackson. ASCE 1989.

Reproduced with permission of the American Society of Civil Engineers.

8.3.4.1.2 Cohesionless (Drained) Soil (KO Method)

Equation 8-13

γ

π γ

=

−

σ φ

= π

−

= +

∑=

q

2

B

EB

H

i 0

v o

SF

T SF EB

H N

4

D

Q

Equation 8 15

F.S.

K (tan )

Q D

Equation 8 14

Q Q Q
Bulletin 1724E-300

Page 481

Where:

D = Diameter of shaft, in m (ft)

DB = Diameter of shaft base, in m (ft)

Ko = Coefficient of lateral earth pressure (generally between active and at-rest states

and dependent upon shaft installation method and soil in situ density)

ã = Effective unit weight of soil, in kg/m3 (pcf)

óv = Effective vertical pressure at point of interest in N/m2 (psf)

φ = Friction angle shaft/soil interaction (generally not in excess of angle of internal

friction of soil strata)

H = Total length of shaft, in meters (feet)

Nq = Bearing capacity factor for deep foundations

F.S. = Factor of safety

The effective vertical stress in cohesionless soils for both the skin friction calculation and end bearing

components are typically limited to their “critical depth.” based on research performed by Vesic. The

critical depth factor depends on soil density and generally varies between 10 to 20 times the shaft

diameter. In theory, the crushing of sand grain particles and the resulting failure to achieve higher skin

friction and end-bearing components occurs at depths where the shaft length exceeds these critical depth

factors, and therefore the maximum effective stress has to be limited in the calculations.

Due to the relatively deep depth of drilled shafts, the bearing capacity factor Nq is generally discounted in

the equation for end bearing and the relatively small percentage of overall capacity.

Consider total shaft settlement due to axial compressive loads. Settlement depends on the elastic

shortening of the shaft and soil characteristics. Consolidation from uncompacted fills, landfills, organic

layers, or collapsible or dispersive soils may result in unacceptable settlement or long-term negative skinfriction (down drag) of shafts. Rock formations should be evaluated to determine the mass formation

properties such as weathering, joints and fractures, and clay filled cracks.

Belled shafts are frequently used where local soil conditions permit short-term stability of the bell.

Where soils permit belled construction, typically cohesive soils and some shales, and total settlement is

not anticipated to be excessive under higher loading, the base diameter may be used when determining the

end bearing capacity. Typically, the length of the shaft occupied by the bell is discounted when

determining the skin friction component.

A factor of safety in compression of 2.0 is typically used for cohesionless soils.

8.3.4.2 Uplift Capacity

8.3.4.2.1 Cohesive (Undrained) Soil: Axial uplift capacity of straight shafts is derived from the skin

friction or adhesion component of the shaft compressive capacity calculated in Equation 8-13. In

addition, the effective dead weight of the shaft may be added (unfactored) to the resistance to uplift. This

effective weight consists of the total weight of the shaft above the ground water level and the buoyant

weight of the shaft below.

Dependent upon the shaft depth-to-diameter ratio, and whether the shaft is belled, other failure surface

concepts have been developed. For relatively shallow shafts or belled shafts, the methodology introduced

by Meyerhof and Adams is recommended. This approach considers the shaft base to perform as an

inverse bearing capacity failure without skin friction support, as either a cone-shaped or curved surface

failure mode.
Bulletin 1724E-300

Page 482

The factor of safety in uplift of 1.5 is typically used for cohesive soils.

8.3.4.2.2 Cohesionless (Drained) Soil: Axial uplift capacity of straight shafts is derived from the skin

friction component of the shaft compressive capacity calculated in Equation 8-14.

An alternative method by Meyerhof and Adams for cylindrical shear has been proposed for comparable

shaft design. However, the construction of belled shafts within a cohesionless soil is impractical and

minimizes the likelihood of this approach, except for shafts that are backfilled entirely after an open

excavation.

A factor of safety in uplift of 1.5 is typically used for cohesionless soils. The effective weight of the

shafts (total above the groundwater level and buoyant below) may be added as an unfactored component.

8.3.5 Spread Footings

8.3.5.1 General: Spread footings comprised of a vertical pier or wall seated on a square or rectangular

slab located at some depth below grade have long been used in substation design.

They are usually preferred for transformers, breakers, and other electrical equipment. They are

economical where only a small quantity of foundations is required. They are reliable and easy to design.

The installation time and costs for spread footings are more than for augered piers because of the

excavation, forming, form stripping, backfilling, and compacting.

Compaction of backfill around spread footings should at least be equal to that of the undisturbed soil

before the footing was installed.

Spread footings should always be seated at a depth below the average frost penetration of the area. See

Figure 8-6.

CAUTION: The engineer should determine if the average frost depth will be sufficient for the prevailing

conditions. Deeper footings may be warranted.

8.3.5.2 Design for Compression: In designing a spread footing for only downward loads, divide the

total net load by the allowable soil-bearing capacity and obtain the area of the footing required.

CAUTION: In granular soils the water table location may have significant effect on the allowable soil

capacity.

Equation 8-16

Where:

A = Area of footing base, in m2 (sf)

Total Net Load = LL + DL – Wt of displaced soil

LL = Maximum weight or force exerted on footing by equipment or structure

DL = Weight of foundation

P = Allowable soil bearing pressure, in kg/m2 (psf)

P

Total Net Load

A =
Bulletin 1724E-300

Page 483

Figure 8-6: Approximate Frost-Depth Contours of the United States. Ref. Joseph E. Bowles,

Foundation Analysis and Design, Figure 7-1. Publisher-McGraw Hill Companies, Copyright © 1988.

Reproduced with permission of the McGraw Hill Companies.

8.3.5.3 Design for Uplift: For the design of a spread footing for uplift only, the ultimate net uplift

force (based on design loads times the appropriate OLF) should be exceeded by the weight of the

foundation and the weight of the soil that rests directly on the slab. Several sizes may be selected before

one is obtained that will result in the desired safety factor, 1.5 minimum. CAUTION: In granular soils,

the water table location may reduce the weight of the soil being relied upon for uplift resistance.

8.3.5.4 Design for Moment: A spread footing subject to overturning may be designed as follows:

Assume:

1. All resistance to overturning is furnished by the vertical load, weight of the concrete footing,

and the weight of the soil block above the footing, the sum of which equals N.

2. The footing is rigid and tips about edge A.
Bulletin 1724E-300

Page 484

Figure 8-7: Spread Footing—General

Equation 8-17

Equation 8-20

Where:

e = Eccentricity measured from the centerline, in m (ft)

Mot = Overturning moment, in kN m (ft-lb)

Equation 8-21

p = Actual soil pressure, in kN/m2 (psf)

A = Area of the footing, in m2 (ft2)

S = Section modulus of the bottom of the footing about the axis which the moment is acting

Equation 8-22

between 1.5 and 2.0 is adequate for external stability 

M

M

F.S.

Equation 8 -19

(resisting moment) 

2

Nb

M

Equation 8 -18

M M H h (overturning moment) 

ot

R

R

ot t

=

=

= +

N

M

e

ot

=

S

M

A

N

p

b

if e

ot < = ±

6

6

2

db S =
Bulletin 1724E-300

Page 485

d = Width of footer, in m (ft)

b = Length of footer, in m (ft)

Figure 8-8: Spread Footing with e <

Figure 8-9: Spread Footing with e >













−

> =

e

b

d

N

p

b

if e

2

3

2

6

6

b

6

b
Bulletin 1724E-300

Page 486

Moments and shears are calculated for the concrete design of the slab and pier, and conventional concrete

design is employed to complete the design:

Equation 8-23

Figure 8-10: Spread Footing Elevation

Where

Mz = Bending moment about point z per unit width, in Nm/m (ft-lbs/ft)

= Distance from toe of footer to bending point

x = Distance from toe of footer to the resultant reaction RR

8.3.5.4.1 Design Example 8-2: Given:

1. Allowable bearing capacity of soil = 140 kN/m2

2. M = 40 kNm Ht = 4.5 kN P = 11.0 kN

3. γ = 1600 kg/m3 (assumed weight of soil)

Assume the water table is very deep and is not a factor.

Weight of pier = (0.6 m)

2

 x 1.5 m x 2400 kg/m3 = 1300 kg

Weight of slab = (2 m)

2

 x .3 m x 2400 kg/m3 = 2880 kg

Weight of soil = (4 m2 – 0.36 m2) x 1.35 m x 1600 kg/m3 =7860 kg

Weight of structure & equipment = (11.0 kN/9.8 N/kg) = 1120 kg

N = 13,160 kg

or 129,4 kN

3 3 2

Equation8 24

3 2 3 3

2 2

l l l

l l l l

l













 +











= −

−













 +











= −

x

p

x

p

V p

x

p

x

p M p z
Bulletin 1724E-300

Page 487

Figure 8-11: Spread Footing Plan

Figure 8-12: Spread Footing—3D Example
Bulletin 1724E-300

Page 488

Check for Overturning:

Locate Resultant Force:

Determine Bending Moment in Slab for use in calculating reinforcing steel:

The footing as shown above is slightly over designed. Additional trials could be made to reduce the size,

if desired. Other steps for completing the reinforced concrete design should be completed by the

engineer.

Determine Bending Moment in Pier for use in calculating reinforcing steel.

Assume that the pier is a vertical cantilever beam.

Figure 8-13: Spread Footing—2D Example

( )

( )

2.7 1.5 okay

48.1 kNm

129.4 kNm F.S.

1m 9.8 N/kg 13,160 kg 129.4 kNm

Mot 40 kNm 1.8 m 4.5 kN 48.1 kNm

= = >

= =

= + =

M R

( )

( )

okay

m

kN 140

m

kN 68.5

1m 0.37 m 2 m

129.4 kN

3

2

therefore p

0.33 m

6

b

0.37 m

13.16 9.8

48.1

e

2 2

= <

−













=

= = > =

( )

( )

( )

( )

M kNm

x

m

kN

x

m m

m

m

m

m

kN

x

m m

m

m

kN

M

11.0

3

2

2

1

68.5

3 1 0.37

0.6

0.6

2

0.6

68.5

31 0.37

0.6

68.5

2

2

2

2 2

=













−

 +











−

= −
Bulletin 1724E-300

Page 489

8.3.6 Slabs on Grade

8.3.6.1 General: Slabs on grade are sometimes used as foundations for miscellaneous equipment

supports, switchgear, breakers, and power transformers. Slabs on grade should be used with caution

where there is a chance of frost heave. This may cause problems with equipment that has rigid bus

connections or in some other way may result in an operational malfunction of the equipment.

Slabs on grade may be satisfactory in frost-prone climates if the subgrade is essentially granular and well

drained.

8.3.6.2 Subgrade Preparation: An important part of the installation of a slab on grade is the

preparation of the subgrade. The soil should be thoroughly mixed and compacted to provide a nearly

homogeneous, firm bearing surface. Proper preparation may help prevent objectionable settlement.

Slabs usually vary in thickness between 30 and 60 cm (12 and 24 inches) depending on the various design

parameters. The slab should bear on the prepared subgrade and not on site stone or stone in oil retention

sumps.

8.3.6.3 Applied Loads: The types of loads (compression and overturning) that are typically present in

spread footings are also present in slab-on-grade foundations for equipment. Compression loads include

the equipment weight and, in soil pressure calculations, the foundation weight. In the case of transformer

foundations, the equipment weight plus the weight of the contained insulating oil has to be included. For

transformers, jacking loads have to be also be considered. The jacking loads are considered by the

structural engineer in a check for local punching failure through the slab. Jacking loads are “point” loads

generated as hydraulic jacks are used to raise and level the transformer on the slab. There are typically

four jacking points, one in each corner of the transformer.

Overturning loads occur when horizontal loads act on the equipment at the top of the slab on grade.

While overturning moments in a spread footing are transferred to the base slab through the concrete

pedestal, overturning loads on a slab on grade are transferred through the base of the equipment. Wind

loads, seismic loads, and horizontal dynamic loads are included in the list of loads that would contribute

to overturning. Horizontal dynamic loads might include the circuit-tripping load from an oil-filled circuit

breaker. Also, equipment eccentricity can contribute to overturning. This is a case where the center of

gravity of the equipment is not in line with the centerline of the slab.

8.3.6.4 Design for Stability: As with spread footings, slab-on-grade foundations have to be designed

to not exceed the allowable soil pressure for the site. The allowable soil bearing pressure is site specific

and should be determined by a geotechnical engineer following a subsurface investigation. In the absence

of subsurface information, a reasonable range can be taken between 48 and 72 kN/m2 (1000 and 1500

psf). This, however, may or may not be a conservative range for the given site.

In addition to keeping the soil pressure below the slab under an allowable limit, an adequate safety factor

against overturning has to be maintained. The approach is similar to that for spread footings.

8.3.6.4.1 Design Example 8-3:

Check the soil bearing pressure and the factor of safety against overturning for a transformer slab based

on the following assumptions:
Bulletin 1724E-300

Page 490

161/13.2 kV transformer weight 110,900 kg

Insulating Oil 58,060

Total transformer weight 168,960 kg x 9.8 N/kg = 1656 kN

Transformer base dimensions: 584 cm x 320 cm

Foundation size: 650 cm long x 400 cm wide x 60 cm thick

Weight of foundation = (6.50 m x 4.00 m x 0.60 m) x 23.6 kN/m3 = 368 kN

(concrete: 23.6 kN/m3 = 150 pcf)

Total vertical load, N = 1656 kN + 368 kN = 2024 kN

Given allowable soil bearing pressure, P, based on soil report = 144 kN/m2 (3000 psf)

Calculate overturning moment Mot.

For a transformer in a seismically active area, seismic load usually controls rather than wind load because

of the transformer’s relatively large mass. For this example, assume the transformer is in seismic

Zone 2A and that it has been determined that seismic loads control.

The horizontal seismic load would be calculated as follows:

Based on IEEE Std. C57.114, “IEEE Seismic Guide for Power Transformers and Reactors,” for a

Zone 2A region, where the weight of the transformer, Wtr, is 1656 kN,

Horizontal Load: 0.2 x Wtr = 331 kN

Vertical Load: 2/3(0.2 x Wtr) = 221 kN

Calculate the overturning moment due to the seismic load:

Given:

The center of gravity of the transformer is 150 cm above the top of the foundation.

The slab is 60 cm thick.

The center of gravity of the transformer is 10 cm off the longitudinal centerline of

the foundation.

Overturning moment (seismic):

Horizontal Load: 331 kN x (1.5 m + 0.60 m) = 695 kN

Vertical Load: 221 kN x 0.10 m = 22 kN

Total seismic overturning moment = 717 kN

Calculate the overturning moment due to equipment eccentricity:

Overturning moment (eccentricity) = 1656 kN x 10 cm

= 166 kNm

Calculate the total overturning moment:
Bulletin 1724E-300

Page 491

Mot = 717 kNm + 166 kNm = 883 kNm

Calculate the soil bearing pressure:

Eccentricity, e = Mot/N

e = 883 kNm/2024 kN = 0.44 m

b/6 = 4.0 m/6 = 0.67 m

e < b/6; therefore, p = N/A ± Mot/S

Slab area, A = 6.5 m x 4.0 m = 26 m2

Slab section modulus, S = 6.5 m x (4.0 m)

2

/6 = 17.3 m3

Soil bearing pressure, p = 2024 kN/26 m2± 883 kNm/17.3 m3

 = 77.8 kN/m2± 51.0 kN/m2

pmax = 128.8 kN/m2 < 144 kN/m2 O.K.

Calculate the safety factor against overturning (has to be greater than 1.5):

Mot = 883 kNm

Calculate the moment that resists overturning (MR):

Weight of transformer = 1656 kN

Weight of foundation = 368 kN

MR = (1656 kN x 1.9 m) + (368 kN x 2 m) = 3882 kNm

F.S. = MR/Mot = (3882 kNm ) / (883 kNm) = 4.4 > 1.5 O.K.

8.3.6.5 Minimum Reinforcing Steel: Foundation reinforcing steel is designed based on the American

Concrete Institute Building Code Requirements for Reinforced Concrete (ACI 318). Although reinforcing

steel design is beyond the scope of this chapter, a certain minimum level of reinforcing has to be

maintained. ACI 318 specifies that a steel area of at least 0.0018 times the gross concrete area has to be

provided. This is provided to prevent shrinkage cracks from forming as the concrete dries. For the

foundation in the example above, the minimum area of reinforcing (As) for a unit width strip of 1 meter

would be:

As = 0.0018 x 1 m x 0.60 m

= 0.00108 m2/m of slab length = 1080 mm2/m of slab length

One combination that would satisfy the above minimum requirement would be:

#5 bars @ 30 cm on center, top and bottom, each way.

The cross-sectional area of a #5 bar = 200 mm2

For #5 top and bottom multiply by 2 bars:

As = (2)200 mm2 x (100 cm/1 m)/30 cm = 1333 mm2/m > 1080 mm2/m O.K.
Bulletin 1724E-300

Page 492

Figure 8-14: Transformer Slab Loading

8.4 OIL POLLUTION

Oil pollution from transformers and other substation equipment is discussed in Chapter 2.

Federal law, the Code of Federal Regulations, 40 CFR, Chapter 1, Parts 110 and 112, requires the

containment of potential oil spills for any facility that contains oil stored underground in excess of 42,000

gallons or a capacity stored above ground in excess of 1320 gallons, or any single container with a

capacity greater than 660 gallons. The regulations further require that when a situation as described

above exists in a substation, and an oil spill could reasonably be expected to discharge into or upon

navigable waters, that a “Spill Prevention, Control, and Countermeasure” plan (SPCC plan) has to be

prepared. Detailed information concerning SPCC plan requirements and preparation are contained in

40 CFR 112. Other sources for a detailed discussion of oil spill prevention requirements and techniques

are ANSI/IEEE Std. 980 and RUS Bulletin 1724E-302, “Design Guide for Oil Spill Prevention and

Control at Substations.”

If oil pollution abatement is necessary, the degree of reliability that is desired has to be decided. The

primary function of all systems is to prevent oil from reaching prohibited areas, including the ground

water table and any navigable waters.
Bulletin 1724E-300

Page 493

A determination has to be made as to whether the system will be self-operating or should be monitored

periodically or seasonally.

8.4.1 Basic Retention System

This system should include an impervious, lined, open or stone-filled sump area around the oil

containment vessel (transformer). Usually stone 5 to 9 cm (2 to 31⁄2 inches) is desirable in the sump area

to provide operators and maintenance personnel easy access to and around the transformer. The size and

gradation of the stone affects the percentage of voids available to store oil. Stone of the size mentioned

above may provide 25 to 40 percent voids. Perforated pipe placed in the bottom of the sump will convey,

by gravity flow, water and oil to an underground storage tank. The tank has to have a sump pump to

periodically pump out the water that has collected from rainfall. The pump may be regulated to cut on

and off by a float valve or pressure switches. The transformer also should have a low-oil-level alarm that

deactivates the sump pump.

At the cutoff position, there should be at least 6 inches of water covering the bottom of the tank. This

enables small or slow oil leaks to be stored on top of the water. The storage tank should be designed to

retain all the oil in one transformer between cutoff water level and inlet pipe.

The oil is removed from the tank by pump trucks.

The system is costly but reasonably reliable. Mechanical failure of the sump pump is a disadvantage.

A variation of the approach discussed above is the utilization of a special oil-sensing control unit that

works with a submersible drainage pump. The pump is placed in a vault outside the sump as described

above. The pump discharges rainwater from the system, but is deactivated by the control unit when oil is

detected.

8.4.2 Oil Separator Tank

This system is feasible only where there is sufficient gradient for gravity discharge from the underground

tank. See Figure 8-15.

The oil or water is collected from the transformer area as it was in the basic retention system. It is

discharged into an oil separator tank. The principle upon which this system operates is that oil is lighter

than water and floats upon it.

The oil separator tank should be designed to contain all the oil in one transformer should a major rupture

occur. This system allows the water to continuously pass through but retains the oil. The oil retained in

the tank has to be pumped into a tank truck and disposed of.

This system is costly but quite reliable.

The oil separator tank principle may be applied to above-grade diked basins where freezing temperatures

are not prevalent.

Modification to the above-grade separator system may be considered when regular inspection is

anticipated. It could consist of a transformer area that is lined and diked with impervious material. A

short piece of 4-inch pipe passes through the dike and contains a shutoff valve that may be left open for

continuous drainage and closed in an emergency when alarms occur or inspection indicates.
Bulletin 1724E-300

Page 494

Figure 8-15: Oil Separator Tank

An alternative approach is to leave the valve closed and then open it as necessary to drain the collected

water at periodic inspections.

This system is relatively economical but requires a greater level of maintenance.

8.4.3 Summary

Each solution to the oil abatement problem is not without its own problems. These should be evaluated

along with system costs when deciding on the most desired system at each substation. The ultimate goal

is to make sure all oil within the substation remains on site.

8.5 REFERENCES

40 CFR 110, “Discharge of Oil.”

40 CFR 112, “Oil Pollution Prevention.”

Adams, J.I., and Radhakrishna, H.S., “The Uplift Capacity of Footings in Transmission Tower Design.”

Preprint of Paper Recommended by IEEE Transmission and Distribution Committee of

IEEE/PES. 1975

American Concrete Institute, Building Code Requirements for Structural Concrete (ACI-318-95) and

Commentary (ACI-318R-95).

ANSI/IEEE Std. 980, “Guide for Containment and Control of Oil Spills in Substations.”

ASTM D422, “Test Method for Particle-Size Analysis of Soils.”

ASTM D854, “Test Method for Specific Gravity of Soils.”

ASTM D1586, “Method for Penetrations Test and Split-Barrel Sampling of Soils.”
Bulletin 1724E-300

Page 495

ASTM D1587, “Practice for Thin-Walled Tube Geotechnical Sampling of Soils.”

ASTM D2113, “Practice for Diamond Core Drilling for Site Investigation.”

ASTM D2166, “Test Method for Unconfined Compressive Strength of Cohesive Soil.”

ASTM D2216, “Test Method for Laboratory Determination of Water (Moisture) Contents of Soil and

Rock.”

ASTM D2487, “Classification of Soils for Engineering Purposes (Unified Soil Classification System).”

ASTM D2488, “Practice for Description and Identification of Soils (Visual-Manual Procedure).”

ASTM D2573, “Test Method for Field Vane Shear Test in Cohesive Soil.”

ASTM D3441, “Test Method for Deep, Quasi-Static, Cone and Friction-Cone Penetration Test of Soil.”

ASTM D3550, “Practice for Ring-Lined Barrel Sampling of Soils.”

ASTM D4318, “Test Method for Liquid Limit, Plastic Limit, and Plasticity Index of Soils.”

ASTM D4719, “Test Method for Pressuremeter Testing in Soils.”

Bowles, Joseph E., Foundation Analysis and Design, New York: McGraw-Hill Book Company, 1988.

Broms, B.B., “Design of Laterally Loaded Piles,” Journal of Soil Mechanics and Foundation Division,

ASCE, May 1965, pp. 79-99.

Broms, B.B., “Lateral Resistance of Piles in Cohesionless Soils,” Journal of Soil Mechanics and

Foundation Division, ASCE Proceedings 3909, Vol. 90, SM3, May 1964, pp. 123-156.

Broms, B.B., “Lateral Resistance of Piles in Cohesive Soils,” Journal of Soil Mechanics and Foundation

Division, ASCE Proceedings 3834, Vol. 90, SM2, March 1964, pp. 27-63.

Broms, B.B., “Tapered Steel Poles Caisson Foundation Design,” Journal of Soil Mechanics and

Foundation Division, ASCE, 1964-1965.

Czerniak, E., “Resistance to Overturning of Single Short Pile,” Journal of the Structural Division, ASCE,

March 1957.

Davisson, M.T., and Shanisher Prakash, “A Review of Soil Pole Behavior,” Highway Research Board

No. 39, 1963.

GAI Consultants, Inc. “Laterally Loaded Drilled Pier Research,” Vol. 1: Design Methodology. Final

Report, Project RP-1280-1. Palo Alto, Cal.: Electric Power Research Institute, 1982.

Hansen, J.B., “Ultimate Resistance of Rigid Piles Against Transversal Forces,” The Danish Geotechnical

Institute, Bulletin No. 12, 1961.

IEEE Std. C57.114, “IEEE Seismic Guide for Power Transformers and Reactors.”
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Page 496

IEEE Std. 691, “Draft American National Standard—IEEE Trial-Use Guide for Transmission Structure

Foundation Design,” Transmission and Distribution Committee of the IEEE Power Engineering

Society, September 1985.

Kulhawy, Fred H., and Christina Stas Jackson, “Some Observations on Undrained Side Resistance of

Drilled Shafts,” Foundation Engineering: Current Principles and Practices, ASCE, 1989,

pp. 1014-1025.

Meyerhof, G.G., “The Ultimate Bearing Capacity of Foundations,” Geotechnique 2(4): 301-332 (1951).

Meyerhof, G.G., and J.I. Adams, “The Ultimate Uplift Capacity of Foundations,” Canadian Geotechnical

Journal 5(4): 225-244 (1968).

Naik, T.R., and Alain Peyrot, “Analysis and Design of Laterally-Loaded Piles and Corrosions in a

Layered Soil System,” University of Wisconsin-Milwaukee, 1980.

Reese, L.C., “Laterally Loaded Piles: Program Documentation,” Journal of Geotechnical Engineering

Division of the American Society of Civil Engineering 103(GT4): 287-305 (April 1977).

Reese, L.C., and M.W. O’Neill, “Drilled Shafts: Construction Procedures and Design Methods,” U.S.

Department of Transportation, Office of Implementation, Publication No. FHWA-HI-88-042,

August 1988.

REA Bulletin 65-1, Design Guide for Rural Substations, 1978.

RUS Bulletin 1724E-200, “Design Manual for High Voltage Transmission Lines.”

RUS Bulletin 1724E-205, “Design Guide: Embedment Depths for Concrete and Steel Poles,” 1995.

RUS Bulletin 1724E-302, “Design Guide for Oil Spill Prevention and Control at Substations.”

Terzaghi, Karl, Theoretical Soil Mechanics, New York: John Wiley & Sons, 1943.

University of Florida-Gainesville, McTRANS (Center for Microcomputers in Transportation),

COM624P, Version 2.0 and Documentation, Developed for FHWA.

U.S. Department of Transportation, Office of Research and Development, Drilled Shaft Manual, Vol. II –

Structural Analysis and Design for Lateral Loading. Publication No. FHWA Implementation

Package 77-21. Washington, USDOT, July 1977.

Vesic, A.S., “Bearing Capacity of Deep Foundations,” Highway Research Board, Record No. 39, 1963,

p. 112-153.

Woodward, R.J., W.S. Gardner, and D.M. Greer, Drilled Pier Foundations, New York: McGraw-Hill,

1972.
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Appendix E

Page 497

APPENDIX E

SPECIFICATION

FOR

PROCURING

GEOTECHNICAL SUBSURFACE INVESTIGATION

The following Specification for Procuring Geotechnical Subsurface Investigation is offered as a general

guideline. This specification is general, incomplete, and prepared in a way to obtain non-professional

geotechnical drilling and testing services, performed in this instance under a specific and pre-defined

scope of work. Therefore, it is geared toward providing only raw data and not professional engineering

recommendations.

Contractual clauses from your cooperative’s legal department should be incorporated along with these

technical specifications. Additional clauses regarding insurance requirements, potentially contaminated

soils, ownership of documents, and limitation of liability are among those issues frequently covered in

common corporate clauses.
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Appendix E

Page 498

SPECIFICATION

FOR

PROCURING

GEOTECHNICAL SUBSURFACE INVESTIGATION

1. SCOPE

1. The work shall consist of making soil borings to determine the nature and extent of the soil strata

at the ____________________ Substation near _______________, __________________ .

Laboratory testing shall be required on undisturbed samples as outlined in the Specifications.

Drawing _____________ is a part of this Specification and indicates the approximate location of

proposed borings.

2. GENERAL

1. The Geotechnical Engineering Consultant (Consultant) shall furnish all necessary equipment,

materials, and labor to complete the borings at the locations shown on Drawing ______________.

2. The Consultant shall be responsible for all damage to public and private property resulting from

the operations of its employees.

3. The Consultant shall also comply with all Federal, State, and local rules and regulations with

regard to permits, bonds, drilling, plugging, and all other applicable aspects of well drilling.

4. The Consultant shall review the proposed scope of work indicated as a minimum level of services

desired relative to the anticipated subsurface conditions present. If localized subsurface

conditions are expected to vary significantly, Consultant shall advise Owner of additional

recommended services prior to commencing work.

5. The Consultant shall evaluate the stratigraphic soil, rock, and phreatic water level information at

the Site so as to assist in configuring the depth and size of the proposed structures.

6. The Consultant shall conduct a subsurface investigation and laboratory testing program and

prepare final boring logs and laboratory results. These services are described in more detail later

in this Specification, but include the following tasks:

a. Perform an exploration program and provide qualified field personnel to log the borings.

b. Perform laboratory tests on samples obtained from the borings to evaluate pertinent

engineering properties of materials encountered.

c. Provide a final report containing a description of the field and laboratory testing programs,

boring location plan, typed boring logs, and laboratory test results.

3. WORKMANSHIP AND METHODS

1. Borings shall be performed by the Consultant at the locations previously staked in the field and as

shown on the Drawing.
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2. In soil that is predominantly cohesionless, Consultant shall perform the standard penetration test

in accordance with ASTM Specification D1586. Consultant shall use a 2" O.D. x 1-3/8" I.D. split

tube sampler and a 140-lb weight free falling 30 inches. Record the number of blows per

12 inches of penetration at each change in stratification or character of the soil but at intervals not

exceeding 3 feet for the first 15 feet below grade and at 5-foot intervals thereafter.

3. In soil that is predominantly cohesive, Consultant shall use the thin-walled tube method for

sampling in accordance with ASTM Specification D1587. Consultant shall take samples in each

change of stratification but at intervals not exceeding 3 feet for the first 15 feet below grade and

at 5-foot intervals thereafter.

4. Boring in hard strata or rock shall be performed by diamond coring in accordance with ASTM

D2113.

5. The depth of borings is indicated on the attached Drawing. If boulders or materials are

encountered that prevent penetration to the required depth, the location of the boring shall be

changed a maximum of 10 feet for a second boring. If refusal occurs on the second boring in less

than 15 feet below grade, the boring shall be considered complete.

6. The Consultant shall be cognizant of the fact that borings are being obtained for foundation

design information. If it becomes apparent during the boring operation that the material

throughout the depth of the borings is unusually soft or the standard penetration values are very

low so that it might appear that piling might be necessary, the Consultant shall so inform the

proper authority, in this case, Mr. Mrs. Ms. who may be

reached at __________________ . The Consultant shall not leave the site until the Consultant is

further notified of what action is desired. Such notification is not anticipated to take more than

one-half day.

7. Borings shall be advanced with drilling methods that minimize the potential for disturbance,

sloughing, or mixing of materials within soil samples. When water is encountered within a hole

in cohesionless or sand material, rotary wash drilling methods with bentonite or polymer slurry

shall be used in which positive head is maintained within the hole. Rotary wash drilling should

be anticipated. Consultant shall provide casing, if required. Water levels encountered, as well as

the method used in advancing drilling, shall be indicated by Consultant on the respective boring

logs.

8. Consultant shall obtain calibrated hand penetrometer readings on all cohesive samples in the

field. Consultant shall seal samples to prevent disturbance and moisture changes and transport to

the laboratory for testing.

9. Laboratory tests shall be assigned by _________________________ and performed by the

Consultant to classify soils and obtain geotechnical physical characteristics. Consultant shall

provide copies of the rough field boring logs upon completion to ________________________

so that laboratory tests may be assigned. Consultant shall perform laboratory testing consistent in

quality with current, applicable ASTM Standards. The following estimate of laboratory testing is

provided as our best estimate at this time and may vary based on actual materials encountered and

samples obtained.

[Insert Table of Anticipated Testing; To Be Prepared by Cooperative]
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Appendix E

Page 500

4. FINAL REPORT

1. Four copies of the final report shall be mailed to Mr. Mrs. Ms. __________________ not later

than two weeks after the drilling operations have been completed.

2. The Consultant’s report shall include the following:

a. Project identification, boring number, location and driller.

b. Depth of topsoil.

c. Elevation of groundwater at completion of boring and also 24 hours after completion,

including dates and times measured.

d. Vertical plot sections, referred-to datum, showing type and descriptive classification of

material encountered and the upper boundary elevation of each successive soil strata.

Descriptive classification shall include group symbol of the Unified Soil Classification

System.

e. Number of blows per 12-inch penetration from standard penetration test.

f. Dry density of soil and moisture content.

g. Unconfined compressive strength tests on all cohesive soils procured and selected from the

samples for testing.

h. Date of beginning and end of boring.

a. If it is necessary to stop boring or move a hole due to obstruction, breaking of casing, etc., it

shall be noted and properly described.
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CHAPTER 9

GROUNDING

9.1 GENERAL

This chapter is concerned with safe grounding practices and design for outdoor ac substations

(distribution and transmission) for power frequencies in the range of 50 to 60 Hz. DC substations and the

effect of lightning surges are not covered by this chapter.

An effective substation grounding system typically consists of driven ground rods, buried interconnecting

grounding cables or grid, equipment ground mats, connecting cables from the buried grounding grid to

metallic parts of structures and equipment, connections to grounded system neutrals, and the ground

surface insulating covering material. Currents flowing into the grounding grid from lightning arrester

operations, impulse or switching surge flashover of insulators, and line-to-ground fault currents from the

bus or connected transmission lines all cause potential differences between grounded points in the

substation and remote earth. Without a properly designed grounding system, large potential differences

can exist between different points within the substation itself. Under normal circumstances, it is the

current flow through the grounding grid from line-to-ground faults that constitutes the main threat to

personnel.

An effective grounding system has the following objectives:

1. Ensure such a degree of human safety that a person working or walking in the vicinity of

grounded facilities is not exposed to the danger of a critical electric shock. The touch and step

voltages produced in a fault condition have to be at safe values. A safe value is one that will

not produce enough current within a body to cause ventricular fibrillation.

2. Provide means to carry and dissipate electric currents into earth under normal and fault

conditions without exceeding any operating and equipment limits or adversely affecting

continuity of service.

3. Provide grounding for lightning impulses and the surges occurring from the switching of

substation equipment, which reduces damage to equipment and cable.

4. Provide a low resistance for the protective relays to see and clear ground faults, which

improves protective equipment performance, particularly at minimum fault.

It should be recognized that there is no overall record of injuries resulting from deficient grounding

systems. Equally, however, it should be appreciated that, with more substations being built, higher fault

currents become possible. Therefore, it is becoming more important to protect against personal injury and

equipment damage.

While line-to-ground faults may result in currents of tens of thousands of amperes lasting several seconds,

modern relay systems generally reduce the fault duration to a few cycles. During fault current flow, a low

ground grid resistance to remote earth, although desirable, will not, in itself, necessarily provide safety to

personnel. It is necessary that the entire grounding system be designed and installed so that, under

reasonably conceivable circumstances, personnel are not exposed to hazardous potential differences

across the body.

Designing a proper substation grounding system is complicated. Numerous parameters affect its design,

and it is often difficult to obtain accurate values for some of these parameters. Furthermore, temperature

and moisture conditions can cause extreme variations in the actual resistivity of the ground in which the
Bulletin 1724E-300

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system is installed. Methods of dealing with the design problem are necessarily based to some extent on

approximations and the exercise of engineering judgment. The design approach has to be conservative

because of the aforementioned uncertainties.

A good grounding system provides a low resistance to remote earth in order to minimize the ground

potential rise. For most transmission and other large substations, the ground resistance is usually about 1

Ω or less. In smaller distribution substations the usually acceptable range is from 1 to 5 Ω, depending on

local conditions.

For reference material, IEEE Std. 80, “Guide for Safety in Substation Grounding,” is generally recognized

as one of the most authoritative guides available. It is recommended for any person concerned with the

design of substation grounding systems. A bibliography in the IEEE guide lists important additional

references, including abstracts of many of them.

This chapter describes some of the different modes in which ground fault current may flow with respect

to substation grounding systems. Included is discussion of safety considerations in and near substations

when all or a portion of this fault current flows through the substation grounding system. Specific

recommendations for the design, installation, and testing of safe and effective grounding systems for RUS

substations are included.

The design procedures presented in this chapter are based on IEEE Std. 80, “Guide for Safety in

Substation Grounding.” IEEE Std. 80 presents a simplified design procedure for substation grounding

that meets the required safety criteria without the use of an expensive computer software program. The

sections of this chapter are presented in the order in which they should be performed.

The first aspect of substation grounding is how to take and analyze soil resistivity measurements (Section

9.3). Next, Section 9.4 shows the importance of the area of the ground grid. Section 9.5 discusses and

illustrates some of the cases governing fault current flow. The engineer will use the split factor (Section

9.5.2) to take into account that not all of the fault current uses the earth as a return path. The split factor

can be calculated from graphs instead of formulas; these graphs are one of the major improvements to

grounding design from previous grounding design manuals.

Once the maximum grid current is determined (Section 9.5.4), the engineer will use the maximum grid

current to choose the type and size of the ground grid conductors needed (Section 9.6). Section 9.6 also

examines how to connect substation equipment to the ground grid and the type of connector to use.

Section 9.7.1 shows the importance of high-speed relays by calculating the tolerable limits of current to

the body, and in Section 9.7.2 the typical shocks situations are illustrated in Figures 9-28 and 9-29 (see

page 541 and 542 of this bulletin). Tolerable touch and step voltages are discussed in Section 9.8, which

are the design criteria of a safe grounding design. Section 9.9 provides the benefits of protective surface

materials, such as gravel, in improving the tolerable touch and step voltages.

In Section 9.10, all the information in the previous sections is pulled together in a step-by-step approach

to designing a substation grounding system. Once a safe ground grid has been designed, the proper

grounding of the substation fence (Section 9.10.10.1) and the operating handles on switches, cable

sheaths, and surge arresters (Section 9.10.10.3) is discussed.
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9.2 DEFINITIONS

9.2.1 DC Offset

Difference between the symmetrical current wave and the actual current wave during a power system

transient condition. Mathematically, the actual fault current can be broken into two parts: a symmetrical

alternating component and a unidirectional (dc) component. The unidirectional component can be of

either polarity, but will not change polarity and will decrease at some predetermined rate.

9.2.2 Earth Current

The current that circulates between the grounding system and the ground fault current source that uses the

earth as the return path.

9.2.3 Ground Fault Current

A current flowing into or out of the earth or an equivalent conductive path during a fault condition

involving ground.

9.2.4 Ground Potential Rise (GPR)

The maximum voltage that a ground grid may attain relative to a distant grounding point assumed to be at

the potential of remote earth. The GPR is equal to the product of the earth current and the equivalent

impedance of the grounding system.

9.2.5 Mesh Voltage

The maximum touch voltage within a mesh of a ground grid.

9.2.6 Soil Resistivity

The electrical characteristic of the soil with respect to conductivity. The value is typically given in ohmmeters.

9.2.7 Step Voltage

The difference in surface potential experienced by a person bridging a distance of 1 meter with his feet

without contacting any other grounded object.

9.2.8 Touch Voltage

The potential difference between the ground potential rise and the surface potential at the point where a

person is standing while at the same time having his hands in contact with a grounded structure.

9.2.9 Transferred Voltage

A special case of the touch voltage where a voltage is transferred into or out of the substation from or to a

remote point external to the substation site.
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9.3 SOIL RESISTIVITY MEASUREMENTS

Before the design process can begin, soil resistivity measurements should be taken at the substation site.

Make these at a number of places within the site. Substation sites where the soil may possess uniform

resistivity throughout the entire area and to a considerable depth are seldom found. Typically, there are

several layers, each having a different resistivity. Often, lateral changes also occur, but, in comparison to

the vertical ones, these changes usually are more gradual. Make soil resistivity tests to determine if there

are any important variations of resistivity with depth. The number of such readings taken should be

greater where the variations are large, especially if some readings are so high as to suggest a possible

safety problem.

A number of measuring techniques are described in detail in IEEE Std. 81-1983. The Wenner four-pin

method as shown in Figure 9-1 is the most commonly used technique. In brief, four probes are driven

into the earth along a straight line, at equal distances a apart, driven to a depth b. The voltage between the

two inner (potential) electrodes is then measured and divided by the current between the two outer

(current) electrodes to give a value of resistance, R. Then,

Equation 9-1

2 2 2 2

4

2

1

4

a b

a

a b

a

aR

a

+

−

+

+

=

p

r

Where:

ra = Apparent resistivity of the soil in Ω-m

R = Measured resistance in ohms

a = Distance between adjacent electrodes in meters

b = Depth of the electrodes in meters

If b is small compared to a, as is the case of probes penetrating the ground only a short distance,

Equation 9-1 can be reduced to Equation 9-2:

Equation 9-2

ρa = 2πaR

The current tends to flow near the surface for the small probe spacing, whereas more of the current

penetrates deeper soils for large spacing. Thus, it is usually a reasonable approximation to assume that

the resistivity measured for a given probe spacing a represents the apparent resistivity of the soil to a

depth of a when soil layer resistivity contrasts are not excessive. Equations 9-1 and 9-2, thus, can be used

to determine the apparent resistivity ra at a depth a.

There are a number of reasons for the popularity of the Wenner four-pin method shown in Figure 9-1.

The four-pin method obtains the soil resistivity data for deeper layers without driving the test pins to

those layers. No heavy equipment is needed to perform the four-pin test. The results are not greatly

affected by the resistance of the test pins or the holes created in driving the test pins into the soil.

Resistivity measurement records should include temperature data and information on the moisture content

of the soil at the time of measurement. Also record all data available on known buried conductive objects

in the area studied. Buried conductive objects in contact with the soil can invalidate resistivity
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measurements if they are close enough to alter the test current flow pattern. This is particularly true for

large or long objects.

Figure 9-1: Wenner Four-Pin Method. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 13-1. Copyright © 1998. IEEE. All rights reserved.

A good reference useful for an understanding of both resistivity and grounding system resistance

measurements is contained in the manual entitled Getting Down-To-Earth by the Biddle Co. This manual

is available from AVO International, 261 Van Buren Rd., Trooper, Pennsylvania 19403, order number

AVTM25TA (www.avointl.com). Helpful information is also given in IEEE Stds. 81 and 81.2.

9.3.1 Analyzing Soil Resistivity Measurements

Interpretation of apparent resistivity obtained in the field is perhaps the most difficult part of the

measurement program. The basic objective is to derive a soil model that is a good approximation of the

actual soil. Soil resistivity varies laterally and with respect to depth, depending on the soil stratification.

Seasonal variations may occur in soil resistivity due to varying weather conditions. It has to be

recognized that the soil model is only an approximation of the actual soil conditions and that a perfect

match is unlikely.

The most commonly used soil resistivity models are the uniform soil model and the two-layer soil model.

Two-layer soil models are often a good approximation of many soil structures while multi-layer soil

models may be used for more complex soil conditions. Interpretation of the soil resistivity measurements

may be accomplished either manually or by use of computer analysis techniques described in numerous

references.

A uniform soil model should be used only when there is a moderate variation in apparent resistivity. In

homogeneous soil conditions, which rarely occur in practice, the uniform soil model may be reasonably

accurate. If there is a large variation in measured apparent resistivity, the uniform soil model is unlikely

to yield accurate results.

A more accurate representation of the actual soil conditions can be obtained through use of a two-layer

model. The two-layer model consists of an upper layer of finite depth and with different resistivity than a

lower layer of infinite thickness. There are several techniques to determine an equivalent two-layer

model from apparent resistivity obtained from field tests. In some instances a two-layer model can be

approximated by visual inspection of a plot of the apparent resistivity versus depth from driven rod

measurements or apparent resistivity versus probe spacing from Wenner four-pin measurements.

Computer programs available to the industry may also be used to derive two-layer and multi-layer soil

models.
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Since the simplified design procedures of IEEE Std. 80 require a uniform soil assumption, a single value

for soil resistivity will have to be chosen.

9.3.2 Uniform Soil Assumption

A uniform soil model can be used instead of the multi-layer soil model whenever the two-layer or multilayer computation tools are not available. Unfortunately, an upper bound of the error on all relevant

grounding parameters is difficult to estimate. In general, however, when the contrast between the various

layer resistivities is moderate, an average soil resistivity value may be used as a first approximation or to

establish orders of magnitude. The approximate uniform soil resistivity may be obtained by taking a

mathematical average of the measured apparent resistivity data as shown in Equation 9-3.

Equation 9-3

( )

( ) ( ) ( ) ( )

r

r r r r

a av

a a a a n

n

1

1 2 3

=

+ + +K +

Where:

ra(1), ra(2), ra(3) ...ra(n) = Measured apparent resistivity data obtained at different spacing in the fourpin method or at different depths in the driven ground rod method in Ω-m

n =Total number of measurements

Other methods to approximate uniform soil resistivity can be found in IEEE Std. 80.

9.4 AREA OF THE GROUND GRID

The area of the ground grid should be as large as possible, preferably covering the entire substation site.

All of the available area should be used since this variable has the greatest effect in lowering the grid

resistance. Measures such as adding additional grid conductor are expensive and do not reduce the grid

resistance to the extent that increasing the area does.

In general, the outer grid conductors should be placed on the boundary of the substation site with the

substation fence placed a minimum of 3 feet inside the outer conductors. This results in the lowest

possible grid resistance and protects persons outside the fence from possibly hazardous touch voltages. It

is therefore imperative that the fence and the ground grid layout be coordinated early in the design

process.

The simplified design equations require square, rectangular, triangular, T-shaped, or L-shaped grids. For

preliminary design purposes, on a layout drawing of the substation site, draw in the largest square,

rectangular, triangular, T-shaped, or L-shaped grids that will fit within the site. These represent the outer

grid conductors and will define the area of the grid to be used in the calculations. A square, rectangular,

triangular, T-shaped, or L-shaped grid site generally requires no additional conductors once the design is

complete. For irregular sites, once the design has been completed, additional conductors will be run

along the perimeter of the site that were not included in the original grid design and connected to the grid.

This will take advantage of the entire site area available and will result in a more conservative design.

9.5 GROUND FAULT CURRENTS

When a substation bus or transmission line is faulted to ground, the flow of ground current in both
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magnitude and direction depends on the impedances of the various possible paths. The flow may be

between portions of a substation ground grid, between the ground grid and surrounding earth, along

connected overhead ground wires, or along a combination of all these paths.

The relay engineer is interested in the current magnitudes for all system conditions and fault locations so

that protective relays can be applied and coordinating settings made. The designer of the substation

grounding system is interested primarily in the maximum amount of fault current expected to flow

through the substation grid, especially that portion from or to remote earth, during the service lifetime of

the installed design.

Figures 9-2 through 9-5 illustrate some of the cases governing ground fault current flow. The worst case

for fault current flow between the substation grounding grid and surrounding earth in terms of effect on

substation safety has to be determined. The maximum symmetrical rms fault current at the instant of fault

initiation is usually obtained from a network analyzer study or by direct computation. IEEE Std. 80

provides methods for direct computation of the maximum symmetrical rms fault current.

Figure 9-2: Fault Within Local Substation, Local Neutral Grounded.

Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 15-1. Copyright © 1998. IEEE. All rights reserved.

Figure 9-3: Fault Within Local Substation, Neutral Grounded at Remote Location.

Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 15-2. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-4: Fault in Substation; System Grounded at Local Station and also at Other Points.

Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 15-3. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-5: Typical Current Division for a Fault on High Side of Distribution Substation.

Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 15-4. Copyright © 1998. IEEE. All rights reserved.
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9.5.1 Symmetrical Grid Current

That portion of the symmetrical ground fault current that flows between the grounding grid and

surrounding earth may be expressed by Equation 9-4:

Equation 9-4

I S I

g = f f

⋅

Where:

Ig = rms symmetrical grid current in amperes

If = rms symmetrical ground fault current in amperes

Sf = Fault current division factor

For the assumption of a sustained flow of the initial ground fault current, the symmetrical grid current can

be expressed by Equation 9-5:

Equation 9-5

Ig = Sf⋅(3I0)

Where:

Io = Symmetrical rms value of Zero Sequence fault current in amperes

For transmission substations, calculate the maximum Io for a single-phase-to-ground fault for both the

present station configuration and the ultimate station configuration. Obtain values for all voltage levels in

the station. Use the largest of these fault current values.

For distribution stations, since the fault current at distribution stations will not increase significantly over

the life of the station as a result of the high impedance of the 34 and 69 kV feeders, the future fault

current can be modeled using a suitable growth factor (suggest value of 1.1 x I0).

For an extremely conservative design, the interrupting rating of the equipment can be used for I0. This

value may be as high as ten times the ultimate single-phase-to-ground fault current. Use of such a large

safety factor in the initial design may make it difficult to design the grid to meet the tolerable touch and

step voltage criteria by any means.

9.5.2 Determine the Split Factor, Sf

The split factor is used to take into account the fact that not all the fault current uses the earth as a return

path. Some of the parameters that affect the fault current paths are:

1. Location of the fault

2. Magnitude of substation ground grid impedance

3. Buried pipes and cables in the vicinity of or directly connected to the substation ground system

4. Overhead ground wires, neutrals, or other ground return paths

The most accurate method for determining the percentage of the total fault current that flows into the

earth is to use a computer program such as EPRI’s SMECC, Substation Maximum Earth Current

Computation. This program and similar programs, however, require an involved data collection effort.

For the purposes of this Bulletin, the graphical method will be used.
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Two types of graphs will be presented:

1. 100 percent remote, 0 percent local fault current contribution

2. 25, 50, and 75 percent local, which corresponds to 75, 50, and 25 percent remote fault current

contribution

Figures 9-6 through 9-21 are for 100 percent remote, 0 percent local fault current contribution. These

represent typical distribution substations with delta-wye grounded transformers, switching stations, and

transmission stations with no local sources of zero-sequence current. Each of these graphs contains a

number of curves representing various combinations of transmission lines and feeders at the substation.

Figure 9-6: Approximate Split Factor Sf 100% Remote, 1 Transmission Line,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C1. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-7: Approximate Split Factor Sf 100% Remote, 1 Transmission Line,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C2. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-8: Approximate Split Factor Sf 100% Remote, 2 Transmission Lines,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C3. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-9: Approximate Split Factor Sf 100% Remote, 2 Transmission Lines,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C4. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-10: Approximate Split Factor Sf 100% Remote, 4 Transmission Lines,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C5. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-11: Approximate Split Factor S f 100% Remote, 4 Transmission Lines,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C6. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-12: Approximate Split Factor S f 100% Remote, 8 Transmission Lines,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C7. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-13: Approximate Split Factor S f 100% Remote, 8 Transmission Lines,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C8. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-14: Approximate Split Factor S f 100% Remote, 12 Transmission Lines,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C9. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-15: Approximate Split Factor S f 100% Remote, 12 Transmission Lines,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C10. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-16: Approximate Split Factor S f 100% Remote, 16 Transmission Lines,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C11. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-17: Approximate Split Factor S f 100% Remote, 16 Transmission Lines,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C12. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-18: Approximate Split Factor S f 100% Remote, No Feeder,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C13. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-19: Approximate Split Factor Sf 100% Remote, No Feeder,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C14. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-20: Approximate Split Factor S f 100% Remote, No Transmission Line,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C15. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-21: Approximate Split Factor S f 100% Remote, No Transmission Line,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C16. Copyright © 1998. IEEE. All rights reserved.

Figures 9-22 through 9-27 are for 25, 50, and 75 percent local, which correspond to 75, 50, and 25 percent

remote fault current contribution. This represents typical transmission substations or generating stations

with X number of transmission lines (feeders are considered transmission lines on this graph). These

stations contain local sources of zero-sequence current such as autotransformers and grounded-wye

generator step-up transformers. The greater the local contribution, the lower the earth current since the

locally contributed fault current usually has a direct conductive path to the system neutral.
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Figure 9-22: Approximate Split Factor Sf 75% Remote, No Feeder,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C17. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-23: Approximate Split Factor Sf 75% Remote, No Feeder,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C18. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-24: Approximate Split Factor Sf 50% Remote, No Feeder,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C19. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-25: Approximate Split Factor Sf 50% Remote, No Feeder,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C20. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-26: Approximate Split Factor Sf 25% Remote, No Feeder,

Low Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C21. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-27: Approximate Split Factor Sf 25% Remote, No Feeder,

High Line Ground Resistance. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure C22. Copyright © 1998. IEEE. All rights reserved.

In calculating the number of transmission lines and feeders, only those that have either overhead shield

wires or solidly grounded neutrals should be counted. If the number of lines falls between the given

curve values, use the curve with the lower number of lines.

To use the graphs, the approximate tower impedance of the transmission lines and feeders should be

known, and the value for the grid resistance has to be calculated. Since the design has not yet been

started, an approximate value can be calculated by using Equation 9-6:

Equation 9-6

R

A

g =

r p

4
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Where:

Rg = Substation ground resistance in Ω

r = Soil resistivity in Ω-m (calculated in Section 9.3.2 ,ra(av1) )

A = Area occupied by the ground grid in m2(calculated in Section 9.4)

Since the soil resistivity and the ground grid area are the two most important variables controlling the

substation ground resistance, Equation 9-6 yields a sufficiently accurate answer to be used for the

X-coordinate on the graphs. Other equations for Rg are presented in IEEE Std. 80. Once the appropriate

graph has been chosen with all the available information, the intersection of the substation ground

resistance and the appropriate curve yields the value for the split factor on the Y-axis. Note that this value

is given as a percentage and should be converted to decimal notation before using in an equation.

9.5.3 The Decrement Factor, Df

The decrement factor accounts for the asymmetrical fault current wave shape during the early cycles of a

fault as a result of the dc current offset. In general, the asymmetrical fault current includes the

subtransient, transient, and steady-state ac components, and the dc offset current component. Both the

subtransient and transient ac components and the dc offset decay exponentially, each having a different

attenuation rate. However, in typical applications of this guide, it is assumed that the ac component does

not decay with time but remains at its initial value.

The decrement factor can be calculated using Equation 9-7:

Equation 9-7

D

T

t

f e

a

f

t

T

f

= + − a





















−

1 1

2

Where:

tf = Time duration of fault in seconds

Ta = X/(ωR) = the dc offset time constant in seconds

For 60 Hz,

Ta = X/(120πR)

The selection of tf should reflect the fastest clearing time (relay plus breaker time) for transmission

substations and worst-case backup clearing time for distribution and industrial substations. This

conservative approach results in the highest Df.

The X/R ratio used in the calculation of Ta is the system X/R ratio, inductive reactance to resistance, at

the fault location for a given fault type. The X and R components of the system subtransient fault

impedance should be used to determine the X/R ratio. The X/R ratio is the rate of decay of any dc offset.

A large X/R ratio corresponds to a large time constant and a slow rate of decay.

Equation 9-7 can be used to compute the decrement factor for specific X/R ratios and fault duration.

Typical values of the decrement factor for various fault durations and X/R ratios are shown in Table 9-1.
Bulletin 1724E-300

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For relatively long fault durations, the effect of the dc offset current can be assumed to be more than

compensated by the decay of the subtransient component of ac current. A decrement factor of 1.0 can be

used for fault durations significantly greater than 1 second.

Table 9-1: Typical Values of Df. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Table 15-1. Copyright © 1998. IEEE. All rights reserved.

Fault duration, tf Decrement factor Df

Seconds Cycles at 60 Hz X/R = 10 X/R = 20 X/R = 30 X/R = 40

0.008 33 0.5 1.576 1.648 1.675 1.688

0.05 3 1.232 1.378 1.462 1.515

0.10 6 1.125 1.232 1.316 1.378

0.20 12 1.064 1.125 1.181 1.232

0.30 18 1.043 1.085 1.125 1.163

0.40 24 1.033 1.064 1.095 1.125

0.50 30 1.026 1.052 1.077 1.101

0.75 45 1.018 1.035 1.052 1.068

1.00 60 1.013 1.026 1.039 1.052

9.5.4 Maximum Grid Current

During a system fault, the fault current will use the earth as a partial return path to the system neutral.

The current that is injected into the earth during a fault results in a ground potential rise. Typically, only a

fraction of the total fault current flows from the grounding system into the earth. This is due to the

transfer of current onto metallic paths such as overhead static shields, water pipelines, etc.

Faults occurring within the substation generally do not produce the worst earth currents since there are

direct conductive paths that the fault current can follow to reach the system neutral (assuming the

substation has a grounded-wye transformer). The faults that produce the largest ground currents are

usually line-to-ground faults occurring at some distance away from the substation.

The maximum grid current is the current that flows through the grid to remote earth and is calculated by

Equation 9-8.

Equation 9-8

I D I G = f g⋅

Where:

IG = Maximum grid current in amperes

Df = Decrement factor for the entire duration of fault tf, found for tf, given in seconds

Ig = rms symmetrical grid current in amperes (calculated in Section 9.5.1)

9.5.5 Asymmetrical Fault

The asymmetrical fault current includes the subtransient, transient, and steady-state ac components, and

the dc offset current component and can be defined as shown in Equation 9-9:

Equation 9-9

I D I F = f f⋅
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Where:

IF = Effective asymmetrical fault current in amperes

If = rms symmetrical ground fault current in amperes

Df = Decrement factor (calculated in Section 9.5.3)

The dc offset in the fault current will cause the conductor to reach a higher temperature for the same fault

conditions (fault current duration and magnitude). In addition, if present, dc offset could result in

mechanical forces and absorbed energy being almost four times the value of an equivalent symmetric

current case.

9.6 GROUND CONDUCTOR

9.6.1 Conductor Material

The two most commonly used materials for grounding in the United States are copper and copper-clad

steel.

9.6.1.1 Copper: Copper is a common material used for grounding. Copper conductors, in addition to

their high conductivity, have the advantage of being resistant to most underground corrosion because

copper is cathodic with respect to most other metals that are likely to be buried in the vicinity.

9.6.1.2 Copper-Clad Steel: Copper-clad steel is usually used for underground rods and occasionally

for grounding grids, especially where theft is a problem. Use of copper, or to a lesser degree copper-clad

steel, ensures that the integrity of an underground network will be maintained for years, so long as the

conductors are of an adequate size and not damaged and the soil conditions are not corrosive to the

material used.

Other types of ground conductor materials are discussed in IEEE Std. 80.

9.6.2 Ground Conductor Sizing

The ground conductor for both the grid and equipment connections should be sized according to

Equation 9-10:

Equation 9-10

















+

+

⋅

















α ρ

=

o a

o m

c r r

kcmil

K T

K T

ln

t

TCAP

197.4

A I

Where:

I = rms fault current in kA

Akcmil = Area of conductor in kcmil

Tm = Maximum allowable temperature in oC

Ta = Ambient temperature in oC

Tr = Reference temperature for material constants in oC

ao = Thermal coefficient of resistivity at 0oC in 1/oC

ar = Thermal coefficient of resistivity at reference temperature Tr in 1/oC

rr = Resistivity of the ground conductor at reference temperature Tr in μΩ-cm
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Ko = 1/αo or (1/αr) – Tr in oC

tc = Fault current duration in seconds

TCAP = Thermal capacity per unit volume from Table 9-2, in J/(cm3·

oC)

Note that ar and rr are both to be found at the same reference temperature of Tr degrees Celsius.

Table 9-2 provides data for ar and rr at 20oC.

The selection of I is different for the equipment ground connection and the ground grid conductors and is

discussed in Sections 9.6.3 and 9.6.4.

Table 9-2: Material Constants Data for Equation 9-10. Ref. IEEE Std. 80,

Table 11-1. Copyright © 1998. IEEE. All rights reserved.

Description Material

Conductivity

(%)

αr

Factor

@ 20°C

(1/°C)

Ko

@ 0°C

(°C)

Fusinga

Temperature

Tm

(°C)

ρr

@ 20°C

(μΩ-cm)

TCAP Thermal

Capacity

[J/(cm3 .°C)]

Copper,

annealed softdrawn

100.0 0.003 93 234 1083 1.72 3.42

Copper,

commercial harddrawn

97.0 0.003 81 242 1084 1.78 3.42

Copper-clad

steel wire

40.0 0.003 78 245 1084 4.40 3.85

Copper-clad

steel wire

30.0 0.003 78 245 1084 5.86 3.85

Copper-clad

steel rodb

20.0 0.003 78 245 1084 8.62 3.85

a

From ASTM standards.

b Copper-clad steel rod based on 0.010 in. (0.254 mm) copper thickness.

9.6.2.1 Formula Simplification: The formula in English units can be simplified to Equation 9-11:

Equation 9-11

A I K t

kcmil = f c

⋅

Where:

Akcmil= Area of conductor in kcmil

I = rms fault current in kA

tc = Fault current duration in seconds

Kf = Constant from Table 9-3 for the material at various values of Tm (fusing temperature or

limited conductor temperature) and using ambient temperature (Ta) of 40 oC

9.6.3 Sizing Equipment Ground Conductor

In determining the size of the equipment ground conductors, use the total fault current since it has to flow

through the equipment ground conductors before it can reach the ground grid and divide among various

conductive and earth paths to reach the system neutral. Use the effective asymmetrical fault current, IF,

for I in Equation 9-10 when sizing the equipment ground conductors.
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Table 9-3: Material Constants Data for Equation 9-11. Ref. IEEE Std. 80,

Table 11-2. Copyright © 1998. IEEE. All rights reserved.

Material Conductivity

(%)

Tm

a

(

oC)

Kf

Copper, annealed soft-drawn 100.0 1083 7.00

Copper, commercial hard-drawn 97.0 1084 7.06

Copper, commercial hard-drawn 97.0 250 11.78

Copper-clad steel wire 40.0 1084 10.45

Copper-clad steel wire 30.0 1084 12.06

Copper-clad steel rod 20.0 1084 14.64

a

See Section 9.6.5 for comments concerning material selection.

9.6.4 Sizing Ground Grid Conductors

IEEE Std. 80 suggests using IG for I in Equation 9-10 in the design of the grid to take advantage of the

fact that not all the fault current flows through the earth and prevent overdesigning the grounding system.

The current IG should, however, reflect the worst fault type and location, the decrement factor, and any

future system expansion. Another more conservative approach is to use IF (Section 9.5.5) for I in

Equation 9-10.

The use of IF will result in a larger conductor that will provide extra strength for installation, take into

account the effects of corrosion, and provide some margin for unexpected future system expansion. It is

best to be conservative and provide an adequate margin when sizing the ground grid conductors as a

result of the expense involved in replacing or upgrading existing ground conductors at a later date.

9.6.5 Additional Conductor Sizing Factors

The designer should take precautions to ensure that the temperature of any conductor and connection in

the grounding installation does not pose a danger to the safe operation of the substation. For instance:

a. Typically, conductors and connections near flammable materials should be subject to more

stringent temperature limitations.

b. If the strength of hard-drawn copper is required for mechanical reasons, then it may be prudent

not to exceed 250oC to prevent annealing of the conductors.

Carefully examine the possible exposure to a corrosive environment. Even when the correct conductor

size and the selected joining (connecting) method have satisfied all the test requirements of IEEE

Std. 837, “Qualifying Permanent Connections Used in Substation Grounding,” it may be prudent to

choose a larger conductor size to compensate for some gradual reduction in the conductor cross section

during the design life of the installation where the soil environment tends to promote corrosion.

9.6.6 Connections from Equipment and Structures to Ground Grid

Pay careful attention to the connections of substation structures, equipment frames, and neutrals to the

ground grid to realize the benefits of an effective ground grid system. Conductors of adequate ampacity

and mechanical strength should be used for the connections between:

1. All ground electrodes, such as grounding grids, rodbeds, ground wells, and, where applicable,

metal, water, or gas pipes, water well casings, etc.
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2. All above-ground conductive metal parts that might accidentally become energized, such as

metal structures, machine frames, metal housings of conventional or gas-insulated switchgear,

transformer tanks, guards, etc. Also, conductive metal parts that might be at a different

potential relative to other metal parts that have become energized should be bonded together,

usually via the ground grid.

3. All fault current sources such as surge arresters, capacitor banks or coupling capacitors,

transformers, and, where appropriate, machine neutrals, lighting, and power circuits.

Solid bare copper ground conductor or wire is usually employed for these ground connections. However,

transformer tanks are sometimes used as part of a ground path for surge arresters on them. Similarly,

most steel or aluminum structures may be used for the ground path if it can be established that their

conductance, including that of any connections, is and can be maintained as equivalent to that of the

conductor that would normally be installed. Where this practice is followed, any paint films that might

otherwise introduce a highly resistive connection should be removed and a suitable joint compound

applied or other effective means, such as jumpers across the connections, taken to prevent subsequent

deterioration of the connection. Do not assume equal division of currents between multiple ground leads

at cross-connections or similar junction points.

Extra ground connections should be considered at all critical locations (such as at equipment neutrals,

surge arrester grounds, operating handles and ground mats, etc.) to ensure an effective grounding

capability even when one conductor is broken or a connection is improperly made. Do not assume equal

division of currents between multiple ground connections.

Securely attach the shortest possible length ground conductor to structures and/or equipment and form the

conductor to conform to the foundation with minimum exposure to mechanical damage. Conductor sizes

for any critical connection should not be smaller than 1/0 AWG to ensure mechanical adequacy.

Periodically inspect all accessible ground leads. Exothermic weld, brazed, or compression-type

connectors can be used for underground connections. However, exothermic welds are widely used and

recommended by RUS for underground connections. Compression connectors if used in grounding

applications should be of a type that compresses the conductor and the connector into a tight homogenous

mass, removing virtually all air. Use an oxide-inhibiting compound with all compression connectors to

seal out air and moisture and prevent oxidation or corrosion in the connection.

Oxidation or corrosion in the connection can create hot spots that can shorten the life of

the connection. With the connection below grade, there is no visual way of knowing

when the connection has failed. A properly installed exothermic connection is a

molecular connection that eliminates the oxidation and corrosion in the connection and

reduces the opportunity for hot spots.

The connector chosen should satisfy the requirements of IEEE Std. 837. Avoid soldered connections

because of the possibility of failure under high fault currents.

9.7 SAFETY CONSIDERATIONS

Under ground fault conditions, the portion of fault current flowing between a substation ground grid and

the surrounding earth, IG , will result in potential gradients within and around the substation. Unless

proper precautions are taken in design, the maximum gradients present can result in a potential hazard to a
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person in or near the substation. In addition to the voltage magnitude of the local gradients, such things

as duration of the current flow, impedances in its path, body resistance, physical condition of the person,

and probability of contact all enter into the safety considerations.

9.7.1 Tolerable Limits of Body Current

The most common physiological effects of electric current on the body, stated in order of increasing

current magnitude, are perception, muscular contraction, unconsciousness, fibrillation of the heart,

respiratory nerve blockage, and burning.

The threshold of perception for the human body is about one milliampere at commercial (50 or 60 Hz)

frequencies. Currents of 1 to 6 mA, often termed let-go currents, though unpleasant to sustain, generally

do not impair the ability of a person holding an energized object to control his muscles and release it.

Higher currents (about 9 to 25 mA) can result in painful situations and affect the muscles so that the

energized object is difficult if not impossible to release. Still higher mA currents can affect breathing and

may cause fatalities if duration (usually on the order of minutes) is long enough. Further current increases

(about 60 mA and above) can result in ventricular fibrillation of the heart. Sixty mA is approximately the

current drawn by a 7.5 watt 120 V lamp. Currents above the level for ventricular fibrillation can cause

heart paralysis, inhibition of breathing, and burns.

Since currents of a magnitude that exceed let-go level can affect breathing, they have to be avoided if the

duration is likely to be long. Fortunately, in most situations in substations, the protective relays will

prevent any fault from lasting that long. Therefore, it is usually those levels of current that can lead to

ventricular fibrillation that form the basis for most potential gradient limitation efforts.

It is assumed that 99.5 percent of all persons can safely withstand, without ventricular fibrillation, the

passage of a current with magnitude and duration determined by Equation 9-12:

Equation 9-12

I

k

t

B

s

=

Where:

I

B

= rms magnitude of the current through the body in amperes

ts = Duration of the current exposure in seconds

k = Constant related to electric shock energy

For a person weighing 50 kg (110 lbs), k = 0.116

For a person weighing 70 kg (155 lbs), k = 0.157

Equation 9-12 is based on tests limited to a range of between 0.03 and 3.0 s, and is not valid for very short

or long durations.

Equation 9-12 indicates that much higher body currents can be allowed where fast operating protective

devices can be relied upon to limit the fault duration. An engineering decision based on judgment is

needed as to whether to use the clearing time of primary high-speed relays, or that of the backup

protection, as the basis for calculation.
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9.7.2 Typical Shock Situations

Figures 9-28 (see page 541 of this bulletin) and 9-29 (see page 542 of this bulletin) show five basic

situations involving a person and grounded facilities during a fault. In these figures Es is the step voltage,

Et is the touch voltage, Em is the mesh voltage, and Etrrd is the transferred voltage.

During a fault, the earth conducts currents emanating from the grid and other permanent ground

electrodes buried below the earth surface.

In the case of conventional substations, the typical case of metal-to-metal touch voltage occurs when

metallic objects or structures within the substation site are not bonded to the ground grid. Objects such as

pipes, rails, or fences not bonded to the ground grid that are located within or near the substation ground

grid area meet these criteria. Substantial metal-to-metal touch voltages may be present when a person

standing on or touching a grounded object or structure comes into contact with a metallic object or

structure within the substation site that is not bonded to the ground grid. Calculation of the actual metalto-metal touch voltage is complex. In practice, hazards resulting from metal-to-metal contact may best be

avoided by bonding potential danger points to the substation grid.

9.8 TOLERABLE TOUCH AND STEP VOLTAGES

The tolerable touch and step voltages are the criteria that have to be met to ensure a safe design. The

lower the maximum touch and step voltages, the more difficult it is to produce an adequate grid design.

In most cases the tolerable touch voltage will be the limiting factor. Figures 9-30 through 9-34 are used

to derive the equations for maximum touch and step voltages.

Figure 9-30: Exposure to Touch Voltage. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 7-1. Copyright © 1998. IEEE. All rights reserved.
Bulletin 1724E-300

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Figure 9-28: Basic Shock Situations. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 8-1. Copyright © 1998. IEEE. All rights reserved.
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Figure 9-29: Typical Situation of External Transferred Potential. Ref. IEEE Std. 80, Draft 13, June 19, 1998, Figure 8-2. Copyright © 1998.

IEEE. All rights reserved.
Bulletin 1724E-300

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Figure 9-31: Impedances in Touch Voltage Circuit.

Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 7-2. Copyright © 1998. IEEE. All rights reserved.

Figure 9-32: Touch Voltage Circuit.

Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 7-3. Copyright © 1998. IEEE. All rights reserved.

Figure 9-33: Exposure to Step Voltage.

Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 7-4. Copyright © 1998. IEEE. All rights reserved.
Bulletin 1724E-300

Page 544

Figure 9-34: Step Voltage Circuit. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 7-5. Copyright © 1998. IEEE. All rights reserved.

The equations for the maximum touch and step voltages are as follows:

Equation 9-13

( ) step B f B E = R + 2R ⋅ I

Equation 9-14

E R

R

I

touch B

f

= + B











 ⋅

2

Where:

Estep = Step voltage in volts

Etouch = Touch voltage in volts

RB = Resistance of the human body to electric current. RB is generally estimated to be 1000 Ω

for dc and 50 or 60 Hz ac current.

Rf = Ground resistance of one foot:

Equation 9-15

Rf = Cs3ρs

Cs is the surface layer derating factor based on the thickness of the protective surface layer spread above

the earth grade at a substation. If no protective surface layer is used, then Cs = 1 and is defined further in

Section 9.9.1.

ρs is the resistivity of the protective surface layer used at the substation in Ω-m. If no protective surface

layer is used, then ρs = ρ = resistivity of homogenous earth as calculated in Section 9.3.2.

I

B

is defined in Section 9.7.1.

Substituting for I

B

, RB, Rf, and k in Equations 9-13, 9-14, and 9-15:
Bulletin 1724E-300

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For body weight of 50 kg (110 lbs):

Equation 9-16

E ( C )

t

step s s

s

50 1000 6

0116

= + ⋅ r

.

Equation 9-17

E ( C )

t

touch s s

s

50 1000 15

0116

= + . ⋅

.

r

For body weight of 70 kg (155 lbs):

Equation 9-18

E ( C )

t

step s s

s

70 1000 6

0157

= + ⋅ r

.

Equation 9-19

E ( C )

t

touch s s

s

70 1000 15

0157

= + . ⋅

.

r

Determine ts. The faster the clearing time of the fault, the less risk there is to personnel. Both tests and

experience show that the chance of severe injury or death is greatly reduced if the duration of a current

flow through the body is very brief. Given all of the above safety factors and using the assumption that

not all of the worst-case conditions will be present at the time of the fault, the worst-case primary

clearing time for the substation can be used. An extremely conservative design would use the backup

clearing time because it ensures a greater safety margin.

9.9 PROTECTIVE SURFACE MATERIAL AND REDUCTION FACTOR CS

A thin layer of highly resistive protective surface material such as gravel spread above the earth grade at a

substation can greatly reduce the available shock current at a substation. The surface material increases

the contact resistance between the soil and the feet of people in the substation. The surface material is

generally 0.08 to 0.15 meter (3 to 6 inches) in depth and extends 0.91 to 1.22 meters (3 to 4 feet) outside

the substation fence. If the surface material does not extend outside the substation fence, then the touch

voltage may become dangerously high.

A test at a substation in France showed that the river gravel used as surface material when moistened had

a resistivity of 5000 Ω-m. A layer 0.1 to 0.15 meter (4 to 6 inches) thick decreased the ratio of body to

short-circuit current by a ratio of 10:1, as compared to the natural moist ground.

The range of resistivity values for the surface material layer depends on many factors, some of which are

kinds of stone, size, condition of stone (that is, clean or with fines), amount and type of moisture content,

atmospheric contamination, etc. Table 9-4 indicates that the resistivity of the water with which the rock is

wet has considerable influence on the measured resistivity of the surface material layer. Thus, surface

material subjected to sea spray may have substantially lower resistivity than surface material utilized in

arid environments.
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Table 9-4 gives typical resistivity values for different types of surface material measured by several

different parties in different regions of the United States. These values are not valid for all types and sizes

of stone in any given region. Perform tests to determine the resistivity of the stone typically used in the

region’s substations.

Table 9-4: Typical Surface Material Resistivities. Ref. IEEE Std. 80,

Table 12-1. Copyright © 1998. IEEE. All rights reserved.

Resistivity of Sample, Ω-m No. Description of

Surface Material Dry Wet

1 Crusher Run Granite with Fines (NC) 140 x 106 1300 (Groundwater,

45 Ω-m )

2

11⁄2 in. (0.04 m) Crusher Run Granite (GA) with

Fines 4000 1200 (Rainwater,

100 Ω-m )

3

3⁄4-1 in. (0.02-0.025 m) Granite (CA) with

Fines —

6513 (10 Minutes After

45 Ω-m Water Drained)

4

#4 (1 -2 in.) (0.025-0.05 m) Washed Granite

(GA) 1.5 x 106

 to 4.5 x 106 5000 (Rainwater,

100 Ω-m )

5

#3 (2-4 in.) (0.05-0.1 m) Washed Granite

(GA) 2.6 x 106 to 3 x 106 10 000 (Rainwater,

100 Ω-m )

6 Size Unknown, Washed Limestone (MI) 7 x 106 2000 - 3000

(Groundwater, 45 Ω-m )

7

Washed Granite, Similar to 3⁄4-in. (0.02 m)

Gravel 2 x 106

10 000

8 Washed Granite, Similar to Pea Gravel 40 x 1065000

9 #57 ( 3⁄4-in.) (0.02 m) Washed Granite (NC) 190 x 106 8000 (Groundwater,

45 Ω-m )

10 Asphalt 2 x 106 to 30 x 10610 000 to 6 x 106

11 Concrete 1 x 106 to 1 x 109 a21 to 100

a

 Oven-dried concrete. Values for air-cured concrete can be much lower due to moisture content.

9.9.1 Reduction Factor Cs

An analytical expression for the ground resistance of the foot on a thin layer of surface material can be

obtained from Equation 9-20:

Equation 9-20

∑ ( )

∞

ρ =

⋅

= +

n 1

m 2nh

n

s

s s

K R

16 b

C 1

Equation 9-21

K

s

s

=

−

+

r r

r r

Where:

Cs = Surface layer derating factor

K = Reflection factor between different material resistivities

rs = Surface material resistivity in ohm-meters
Bulletin 1724E-300

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r = Resistivity of the earth beneath the surface material in ohm-meters

hs = Thickness of the surface material in meters

b = Radius of the circular metallic disc representing the foot in meters

Rm(2nhs)= Mutual ground resistance between the two similar, parallel, coaxial plates, separated by a

distance (2nhs), in an infinite medium of resistivity rsin ohm-meters

Because the quantity Cs is rather tedious to evaluate without the use of a computer, these values have been

precalculated for b = 0.08 m and are given in the form of graphs in Figure 9-35.

Figure 9-35: Cs versus hs. Ref. IEEE Std. 80, Draft 13, June 19, 1998,

Figure 7-6. Copyright © 1998. IEEE. All rights reserved.

The value for Cs can be read off the Y-axis of Figure 9-35 by finding the intersection of the appropriate

curve for K with the thickness of the surface layer of rock. For the initial design, this value should be set

to 0.101 meter (4 inches) unless a standard thickness is typically used.
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9.10 DESIGN OF A SUBSTATION GROUNDING SYSTEM

9.10.1 General Concepts

The prevailing practice for a grounding system of most utilities both in the United States and other

countries is the use of buried horizontal conductors in the form of a grid, supplemented by a number of

vertical ground rods connected to this grid. Some of the reasons behind the system of vertical rods and

horizontal conductors are that horizontal (grid) conductors are most effective in reducing the danger of

high step and touch voltages on the earth surface. Vertical ground rods penetrating the lower resistivity

soil are far more effective in dissipating fault currents whenever a two- or multi-layer soil is encountered

and the upper soil layer has a higher resistivity than the lower soil layer. This is important because the

resistivity of lower soil layers remains nearly constant with changing seasons while the upper soil layer

resistivity may experience high resistivity conditions with seasonal changes due to the freezing or drying

of the upper soil layer.

Several parameters define the geometry of the grid, but the area of the grounding system, the conductor

spacing, and the depth of the ground grid have the most impact on the mesh voltage, while parameters

such as the conductor diameter and the thickness of the surfacing material have less impact. The area of

the grounding system is the single most important geometrical factor in determining the resistance of the

grid. The larger the area grounded, the lower the grid resistance and, thus, the lower the GPR.

9.10.2 Design Procedures

1. The grounding system grid shall consist of a network of bare conductors buried in the earth to

provide for grounding connections to grounded neutrals, equipment ground terminals,

equipment housings, and structures and to limit the maximum possible shock current during

ground fault conditions to safe values. If the calculated mesh and step voltages of the grid

design are below the maximum values for touch and step voltage, then the design is considered

adequate. Personnel may still receive a shock during fault conditions, but that shock will not

be sufficient to cause ventricular fibrillation.

2. The ground grid should encompass all of the area within the substation fence and extend at

least 0.91 meter (3.0 feet) outside the substation fence. A perimeter grid conductor should be

placed 0.91 meter (3.0 feet) outside and around the entire substation fence including the gates

in any position. A perimeter grid conductor should also surround the substation equipment

and structure cluster in cases where the fence is located far from the cluster.

3. A soil resistivity test, such as described in Section 9.3, will determine the soil resistivity

profile and the soil model needed (that is, uniform or two-layer model). Estimates of the

preliminary resistance of the grounding system in uniform soil can be determined using

Equation 9-3. For the final design, more accurate estimates of the resistance may be desired.

Computer analysis based on modeling the components of the grounding system in detail can

compute the resistance with a high degree of accuracy, assuming the soil model is chosen

correctly.

4. The fault current 3I0 should be the maximum expected future fault current that will be

conducted by any conductor in the grounding system, and the time tc should reflect the

maximum possible clearing time (including backup).
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5. The tolerable touch and step voltages are determined by equations given in Section 9.8. The

choice of time ts is based on the judgment of the design engineer, with guidance from IEEE

Std. 80 (clauses 5.2 to 6.3). Using the assumption that not all the worst-case conditions will be

present at the time of the fault, the worst-case primary clearing time for the substation can be

used for ts. An extremely conservative design would use the backup clearing time for ts.

6. The equipment ground conductor size is determined according to Section 9.6.2.

7. The entire area inside the fence and including a minimum of 1.0 meter (3.3 feet) outside the

fence needs to be covered with a minimum layer of 10 cm (4 inches) of protective surface

material such as crushed rock (or approved equal) possessing a minimum resistivity of

3,000 ohm-meters wet or dry.

8. The ground grid consists of horizontal (grid) conductors placed in the ground to produce

square mesh. This can be visualized as a checkerboard pattern. One row of horizontal

conductors is equally spaced 3 to 15 meters (9.8 to 49.2 feet) apart. A second row of equally

spaced horizontal conductors running perpendicular to the first row is spaced at a ratio of 1:1

to 1:3 of the first row’s spacing. For example, if the first row spacing was 3 meters (9.8 feet),

the second row spacing could be between 3 to 9 meters (9.8 to 29.5 feet). The crossover point

for the first and second row of conductors should be securely bonded together. The purpose of

the bonded connections is to ensure adequate control of surface potential, secure multiple

paths for fault currents, minimize the voltage dorp in the grid, and provide a certain measure of

redundancy in case of conductor failure. Grid conductors range in size from 2/0 AWG

(67 mm

2

) to 500 kcmil (253 mm2); the conductor diameter has negligible effect on the mesh

voltage. The actual grid conductor size is calculated in accordance with Section 9.6.4.

9. Grid conductors should be buried a minimum of 0.46 meter (18 inches) to 1.5 meters

(59.1 inches) below final earth grade (excluding crushed rock covering) and may be plowed in

or placed in trenches. In soils that are normally quite dry near the surface, deeper burial may

be required to obtain desired values of grid resistance.

10. Vertical ground rods may be at the grid corners and at junction points along the perimeter.

Ground rods may also be installed at major equipment, especially near surge arresters. In

multi-layer or high-resistivity soils, it might be useful to use longer rods or rods installed at

additional junction points. Vertical ground rods should be 1.6 cm (5/8 inch) diameter by at

least 2.5-meter (8.0-foot) long copper, steel, or other approved type from the List of Materials,

RUS IP 202-1. Where used, they should be installed with tops 5 cm (1.97 inches) minimum

below grade and bonded to the ground grid connectors. A good design practice is to space

rods not closer than their length. An additional determinant is having enough rods so that their

average fault current pickup would not exceed 300 amperes, assuming all ground system

current entering the grid through the rods.

11. If the GPR calculated according to Section 9.10.6 of the preliminary design is below the

tolerable touch voltage, no further analysis is necessary. The design needs only the

refinements required to provide access to equipment grounds.

12. The calculation of the mesh and step voltages for the grid as designed can be done using the

approximate analysis techniques described in Sections 9.10.4 and 9.10.5 for uniform soil.
Bulletin 1724E-300

Page 550

13. If the computed mesh voltage is below the tolerable touch voltage, the design may be

complete. If the computed mesh voltage is greater than the tolerable touch voltage, the

preliminary design should be revised (see Section 9.10.7).

14. Both the computed touch and step voltages have to be below the tolerable voltages. If not, the

preliminary design has to be revised (see Section 9.10.7).

15. If either the step or touch tolerable limits are exceeded, revision of the grid design is required.

These revisions may include smaller conductor spacing, additional ground rods, etc. More

discussion on the revision of the grid design to satisfy the step and touch voltage limits is

given in Section 9.10.7.

16. After satisfying the step and touch voltage requirements, additional grid and ground rods may

be required. The additional grid conductors may be required if the site is irregular or if the

grid design does not include conductors near equipment to be grounded. Additional ground

rods may be required at the base of surge arresters, transformer neutrals, etc. Also review the

final design to eliminate hazards due to transferred potential (Section 9.10.11) and hazards

associated with special areas of concern (Section 9.10.10).

9.10.3 Preliminary Design

The design criteria are the tolerable touch and step voltages. For a preliminary design, the grid will

consist of uniform square or rectangular mesh. This is so the touch and step voltages calculated by the

simplified design equations of IEEE Std. 80 are valid for every location within the ground grid. Once a

safe preliminary design has been achieved, then the ground grid may be modified so that the grid does not

consist entirely of uniform square or rectangular mesh. These modifications are described in Section

9.10.2, Step 16. Make sure that all grid modifications do not result in mesh that is larger than the one

used in the preliminary design since it could result in unsafe touch and step voltages. Remember that

additional ground conductors added to the preliminary design will result in a more conservative design,

and fewer ground conductors than the preliminary design could result in an unsafe design.

Take the following steps to arrive at a preliminary design:

1. On a layout drawing of the substation site, draw in the largest square, rectangular, triangular,

T-shaped, or L-shaped grids that will fit within the site; this should already have been done to

calculate the grid area in Section 9.4.

2. Place grid conductors to produce square mesh of approximately 6.1 to 12.2 meters (20 to

40 feet) on a side.

3. Set the grid depth, h, equal to 45.72 cm (18 inches).

4. Set the thickness of surface material equal to 10.16 cm (4 inches).

5. Place ground rods around the perimeter of the substation. As a general rule, place a ground rod

at every other perimeter grid connection and at the corners of the substation. Since ground rods

discharge most of their current through their lower portion, they are effective in controlling the

large current densities (and associated large step and touch potentials) that are present in the

perimeter conductors during fault conditions.
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9.10.4 Calculate Design Mesh Voltage

Mesh voltage (a form of touch voltage) is taken as being from a grounded structure to the center of a

rectangle of the substation grounding grid mesh. Mesh voltages represent the highest possible touch

voltages that may be encountered within a substation’s grounding system and thus represent a practical

basis for designing a safe grounding system for within, and immediately outside, the substation fence

area. The mesh voltage has to be less than the tolerable touch voltage for the grounding system to be safe.

However, the mesh voltage may not be the worst-case touch voltage if ground rods are located near the

perimeter, or if the mesh spacing near the perimeter is small. In these cases, the touch voltage at the

corner of the grid may exceed the corner mesh voltage.

In a substation that utilizes a grid as part of the grounding system, it is theoretically possible to design and

install the grid in such a way that the mesh voltage can be kept within desired limits.

The mesh voltage values are obtained as a product of the geometrical factor Km, a corrective factor Ki

that accounts for some of the error introduced by the assumptions made in deriving Km, the soil resistivity

(r), and the average current per unit of effective buried length of the grounding system conductor (IG/LM):

Equation 9-22

E

K K I

m L

m i G

M

=

r ⋅ ⋅ ⋅

Where:

ρ = Soil resistivity, Ω-m

Km = Spacing factor for mesh voltage, simplified method

Ki = Correction factor for grid geometry, simplified method

IG = Maximum grid current that flows between ground grid and surrounding earth

(including dc offset) in amperes

LM = Effective length of Lc + LR for mesh voltage in meters

Lc = Total length of grid conductor in meters

LR = Total length of ground rods in meters

The geometrical factor Km is expressed by Equation 9-23:

Equation 9-23

( )

( )

K

D

h d

D h

D d

h

d

K

K n

m

ii

h

=

⋅

⋅

⋅ ⋅

+

+ ⋅

⋅ ⋅

−

⋅

















+ ⋅

⋅ −





























1

2 16

2

8 4

8

2 1

2

2

p p

ln ln

Where:

D = Spacing between parallel conductors in meters

d = Diameter of grid conductors in meters

h = Depth of ground grid conductors in meters

n = Geometric factor composed of factors na, nb, nc, and nd

Kh = Corrective weighting factor that emphasizes the effects of grid depth, simplified method

Kii = Corrective weighting factor that adjusts for the effects of inner conductors on the corner

mesh, simplified method
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Page 552

For grids with ground rods along the perimeter, or for grids with ground rods in the grid corners as well as

both along the perimeter and throughout the grid area,

Kii = 1

For grids with no ground rods or grids with only a few ground rods, none located in the corners or on the

perimeter:

Equation 9-24

( )

K

n

ii

n

=

⋅

1

2

2

Equation 9-25

K

h

h

h

o

= 1+ ho = 1 m (grid reference depth)

The effective number of parallel conductors in a given grid, n, can be made applicable both to rectangular

or irregularly shaped grids that represent the number of parallel conductors of an equivalent rectangular

grid:

Equation 9-26

n n n n n a b c d= ⋅ ⋅ ⋅

Where:

Equation 9-27

n

L

L

a

C

p

=

2 ⋅

nb = 1 for square grids

nc = 1 for square and rectangular grids

nd = 1 for square, rectangular, and L-shaped grids

Otherwise:

Equation 9-28

n

L

A

b

p

=

4⋅

Equation 9-29

n

L L

A

c

x y

A

Lx Ly

=

 ⋅











⋅

⋅

0.7
Bulletin 1724E-300

Page 553

Equation 9-30

2 2

x y

m

d

L L

D

n

+

=

LC = Total length of the conductor in the horizontal grid in meters

Lp = Peripheral length of the grid in meters

A = Area of the grid in m2

Lx = Maximum length of the grid in the x direction in meters

Ly = Maximum length of the grid in the y direction in meters

Dm = Maximum distance between any two points on the grid in meters

D = Spacing between parallel conductors in meters

d = Diameter of grid conductors in meters

h = Depth of ground grid conductors in meters

The irregularity factor, Ki, used in conjunction with the above-defined n is expressed by Equation 9-31:

Equation 9-31

Ki = 0.644 + 0.148⋅ n

For grids with no ground rods, or grids with only a few ground rods scattered throughout the grid but

none located in the corners or along the perimeter of the grid, the effective buried length, LM , is expressed

by Equation 9-32:

Equation 9-32

LM L L C R= +

Where:

LR = Total length of all ground rods in meters

For grids with ground rods in the corners, as well as along the perimeter and throughout the grid, the

effective buried length, LM , is expressed by Equation 9-33:

Equation 9-33

L L

L

L L

L M C

r

x y

R

= + +

+

































155 122

2 2

. .

Where:

Lr = Length of each ground rod in meters

9.10.5 Step Voltage (Es)

Step voltages within a grid system designed for safe mesh voltages will be well within tolerable limits.

This is because step voltages are usually smaller than touch voltages, and both feet are in series rather

than parallel. Also, the body can tolerate higher currents through a foot-to-foot path since the current
Bulletin 1724E-300

Page 554

does not pass close to the heart. The step voltage has to be less than the tolerable step voltage for the

ground system to be safe.

The step voltage values are obtained as a product of the geometrical factor Ks, the corrective factor Ki, the

soil resistivity (r), and the average current per unit of buried length of grounding system conductor

(IG/LS):

Equation 9-34

E

K K I

s L

s i G

S

=

r⋅ ⋅ ⋅

Where:

ρ = Soil resistivity, Ω-m

Ks = Spacing factor for step voltage, simplified method

Ki = Correction factor for grid geometry, simplified method

IG = Maximum grid current that flows between ground grid and surrounding earth (including dc

offset) in amperes

LS = Effective buried conductor length in meters

For grids with or without ground rods, the effective buried conductor length, LS , is expressed by

Equation 9-35:

Equation 9-35

L L L S C R= 0.75 ⋅ + 0.85 ⋅

Where:

Lc = Total length of grid conductor in meters

LR = Total length of ground rods in meters

The maximum step voltage is assumed to occur over a distance of 1 meter, beginning at and extending

outside the perimeter conductor at the angle bisecting the most extreme corner of the grid. For the usual

burial depth of 0.25 m < h < 2.5 m, Ks is expressed by Equation 9-36:

Equation 9-36

K ( )

h D h D

s

n

=

⋅

+

+

+ −













1 1 −

2

1 1

1 05

2

p

.

Where:

D = Spacing between parallel conductors in meters

h = Depth of ground grid conductors in meters

n = Geometric factor composed of factors na, nb, nc, and nd

9.10.6 Ground Potential Rise (GPR)

In all the above situations for step, touch, and transferred voltage, the actual voltage potential encountered

by the person involved is related to the ground potential rise of the grounding system above remote earth.

This fact stresses the importance of keeping that value as low as possible.
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Ground potential rise is the maximum electrical potential that a substation grounding grid may attain

relative to a distant grounding point assumed to be at the potential of remote earth. This voltage, GPR, is

equal to the maximum grid current times the grid resistance:

Equation 9-37

VGPR = IG Rg

Where:

VGPR = Ground potential rise in volts

IG = Maximum grid current in amperes (calculated in Section 9.5.4)

Rg = Ground grid resistance in Ω

Equation 9-38

R

L A h A

g

T

= + +

+























r 

1 1

20

1

1

1 20 /

Where:

h = Depth of the grid in meters

A = Area occupied by the ground grid in m2 (calculated in Section 9.4)

LT = Total buried length of conductors in meters

ρ = Soil resistivity in Ω-m (calculated in Section 9.3.2 , ρa(av1) )

Equation 9-38 shows that the larger the area covered by the grounding system and the greater the total

length of the grounding conductor used, the lower will be the value of Rg for a given average earth

resistivity. Equation 9-38 also shows that a low earth resistivity is very important in keeping Rg low.

Earth resistivity varies with the temperature and moisture content of the soil and whether the soil is frozen

or unfrozen. For a given location, the earth resistivity is usually not controlled by the substation designer,

although, in cases of very high soil resistivity, special treatments are sometimes used to help lower the

value of ρ.

Whenever the product IgRg results in a voltage below the tolerable touch voltage determined according to

Section 9.8, there is no danger of ventricular fibrillation to most humans from body contact in any of the

cases discussed. If the product IgRg is in excess of allowable voltage values, then attention has to be given

to elimination of possible exposure to transferred potentials and further investigation of touch and step

potentials.

9.10.7 Design Modifications

If the calculated grid mesh and step voltages are much greater than the maximum touch and step voltages,

then the preliminary design has to be modified. To reduce the grid mesh and step voltages, the following

modifications can be tried:

1. Decrease the mesh size by increasing the number of parallel conductors in each direction.

2. Increase the thickness of the layer of surface rock. A practical limit to the depth of the rock

may be 15.24 centimeters (6 inches).
Bulletin 1724E-300

Page 556

3. Limiting the total fault current, if feasible will decrease the GPR and all gradients in

proportion. Other factors, however, will usually make this impractical. Moreover, if

accomplished at the expense of greater fault clearing time, the danger may be increased rather

than diminished.

Other effective measures can be taken to reduce the design mesh and step voltages. Their effects cannot

be modeled using the simplified design equations and have to be modeled using a computer program such

as EPRI SGSYS. These measures include the following:

1. Place additional parallel conductors around the perimeter of the grid to produce smaller

perimeter mesh. The smaller mesh will reduce the mesh and step voltages at the perimeter of

the grid. The resulting unequally sized mesh throughout the grid violates one of the

assumptions of the simplified design equations.

2. Divert fault current to alternative paths. Diverting fault current is generally accomplished by

ensuring that all power line overhead shield wires that enter the substation are connected to the

ground grid. The split factor calculated according to Section 9.5.2 assumes that all shield

wires have already been connected to the grid. Using larger shield wires or shield wires of a

higher conductivity may divert additional fault current. For very small substation sites with

high soil resistivities, this may be the only method that will bring the grid design into

conformance with the safety criteria.

3. If a two-layer soil model indicates that the bottom soil layer has a lower resistivity than the

upper soil layer and lies deeper than 3.05 meters (10 feet), use longer ground rods to reach the

lower resistivity layer.

4. At a site with high-resistivity soil, drill a well and use it as a point of low resistance.

If all the above methods fail to obtain a grid design with safe mesh and step voltages, study and apply the

following modifications where appropriate.

1. Supplementing the grid conductors with deeply placed electrodes. This is required where the

earth in which the grid conductors are buried is of resistivity too high to economically achieve

a satisfactory resistance to remote earth. Such a situation may occur because of the natural

character of the earth. High earth resistivity may also be seasonal because of the earth’s

drying out or becoming frozen. A decision on application of electrodes should necessarily be

conservative because of the probabilistic nature of the problem. Seriously consider

application of deep electrodes wherever relatively high resistivity in shallow earth will be

experienced.

Rods are the most commonly used electrodes. Other types of electrodes, such as ground wells,

are also used.

2. Use of soil additives and treatments to increase the soil conductivity by reducing the resistivity

of the soil. Refer to clause 14.5 of IEEE Std. 80 for additional information.

3. Use of wire mats. It is feasible to combine both a surface material and fabricated mats made

of wire mesh to equalize the gradient field near the surface. A typical wire mat might consist

of copper-clad steel wires of No. 6 AWG, arranged in a 0.6 x 0.6 meter (24 x 24 inch) grid
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pattern, installed on the earth’s surface and below the surface material, and bonded to the main

grounding grid at multiple locations.

4. Wherever practical, use of a nearby deposit of low-resistivity material of sufficient volume to

install an extra (satellite) grid. This satellite grid, when sufficiently connected to the main

grid, will lower the overall resistance and, thus, the ground potential rise of the grounding

grid. The nearby low-resistivity material may be a clay deposit or it may be a part of some

large structure, such as the concrete mass of a hydroelectric dam.

5. Barring access to certain areas, where practical, to reduce the probability of hazards to

personnel.

9.10.8 Application of Equations for Em and Es

Several simplifying assumptions are made in deriving the equations for Em and Es. The equations were

compared with more accurate computer results from cases with various grid shapes, mesh sizes, numbers

of ground rods, and lengths of ground rods, and found to be consistently better than the previous

equations. These cases included square, rectangular, triangular, T-shaped, and L-shaped grids. Cases

were run with and without ground rods. The total ground rod length was varied with different numbers of

ground rod locations and different ground rod lengths. The area of the grids was varied from 6.25 to

10,000 m2(67.27 to 107,639.10 ft2). The number of mesh openings along a side was varied from 1 to 40.

The mesh size was varied from 2.5 to 22.5 meters (8.2 to 78.8 feet). All cases assumed a uniform soil

model and uniform conductor spacing. Most practical examples of grid design were considered. The

comparisons found the equations to track the computer results with acceptable accuracy.

9.10.9 Use of Computer Analysis in Grid Design

Several reasons justify the use of computer analysis in designing the grounding system:

1. Parameters exceed those of the simplified design equation.

2. A two-layer or multi-layer soil model is preferred because of significant variations in soil

resistivity.

3. Uneven grid conductor or ground rod spacing cannot be analyzed using the approximate

methods presented in this chapter.

4. More flexibility in determining local danger points may be desired.

5. The presence of buried metallic structures or conductors not connected to the grounding

system introduces complexity to the system.

6. The preliminary design can be optimized and analyzed.

9.10.10 Special Danger Points

9.10.10.1 Substation Fence Grounding: The grounding of the substation fence is critical because the

fence is generally accessible to the public. The substation grounding design should be such that the touch

potential on both sides of the fence is within the calculated tolerable limit of touch potential.
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The substation fence should be connected to the main ground grid by means of an outer grid conductor

installed a minimum of 0.91 meter (3 feet) (approximately one arm’s length) outside the substation fence

as shown in Figure 9-36. Connections to the outer grid conductor should be made at all corner posts and

at line post every 12.92 to 15.24 meters (40 to 50 feet). The gateposts should be securely bonded to the

adjacent fence as shown in Figure 9-36, detail A. It is recommended that all gates swing inward and be

designed and installed to prevent an outward swing. If gates are installed with an outward swing, then the

ground grid should extend a minimum of 0.91 meter (3 feet) past the maximum swing of the gate. The

reasons to extend the ground grid to cover the swing of the gate are the same as the reason to install a

ground conductor 0.91 meter (3 feet) outside the fence. The voltage above remote earth decreases rapidly

as one leaves the substation grounding area. For example, if a person standing outside the substation

grounding grid touches a fence or outward-swung gate under substation fault conditions, the resulting

potential difference could be large enough to pose a serious danger.

9.10.10.2 Operating Handles: Equipment operating handles are a special circumstance because of

the higher probability for coincidence of adverse factors, namely, the presence of a person contacting

grounded equipment and performing an operation that can lead to electrical breakdown.

If the grounding system is designed conservatively for safe mesh potentials, then the operator should not

be exposed to unsafe voltages. However, because of the uncertainty inherent in substation grounding

design, a metal grounding platform (mat), connected to the operating handle should be placed where the

operator should stand on it to operate the device regardless of whether the operating handle is insulated.

Considerations involved in the switch grounding platform ground conductor include the following:

1. Proper grounding calculations and grid design should result in acceptable touch and step

potential voltages without the additional grounding platform grounding. However, since the

operation of the switch places the operator directly at risk when a substation fault occurs,

additional precautions are needed. This includes adding switch grounding platforms and a 3-

to 6-inch layer of clean crushed rock that covers the entire area inside the substation fence and

extends 3 to 4 feet outside the substation fence to reduce the risk of electric shock.

2. Switch grounding platform grounding is added to minimize the voltage between the switch

operator’s hands and feet in the event of a fault at the switch during manual operation.

3. The basic methods to minimize the hand-to-foot voltage at the switch handle include the

following:

a. Minimize the current that flows in the conductor that connects the equipment grasped by

the hand and the surface that is stood on.

b. Minimize the resistance of the electrical connection between the hands and feet.

The grounding platform should be connected to the operating handle by a copper cable that connects to

the operating handle and the grounding platform as shown in Figure 9-37.
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Figure 9-36: Typical Chain Link Fence
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Figure 9-37: Typical Switch Grounding
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Figure 9-37 provides a grounding system for a switch operator operating the switch handle. With no

other ground cable connection to the grounding platform, minimal current will flow through the

operator’s body to the platform since it will be insulated from the earth and conductor because of the

surface rock. The hand-to-foot voltage will be minimized and closely maintained with this connection.

The grounding platform area needs to be kept clean of contamination and vegetation. If the grounding

platform conductor to the switch handle breaks, then the contamination or vegetation touching the

grounding platform can result in the grounding platform’s potential being close to that of the ground grid,

which is a less safe situation.

The design engineer should be familiar with the application of switch handle grounding and operator

platform grounding by utilizing the latest available standard and publications including RUS document

updates on this subject. The engineer also should develop a safety procedure checklist regarding all

grounding aspects of the switch operator handle for the utility maintenance crew to follow before

attempting to operate the switch.

9.10.10.3 Metallic Cable Sheaths: Metallic cable sheaths in power cable have to be effectively

grounded to prevent dangerous voltages resulting from insulation failure, electrostatic and

electromagnetic induction, flow of fault current in the sheath, and voltage rise during fault current flow in

the substation ground system to which the sheaths are connected. Cable sheaths should be grounded at

two or more locations: at cable terminations and at splices and taps. Control cable shields are not

intended to carry significant current and thus should only be grounded at one end. Where any cable

sheath may be exposed to excessive ground current flow, a parallel ground cable should be run and

connected to both ends. IEEE Std. 80 provides more information on metallic cable sheath grounding.

9.10.10.4 Surge Arrester Grounding: Surge arresters are designed to pass surge energy from

lightning and switching transients to ground and so are frequently subjected to abnormal current flow to

ground. They have to be reliably grounded to ensure protection of the equipment they are protecting and

to minimize high potential gradients during operation.

The surge arrester grounds should be connected as close as possible to the ground terminals of the

apparatus to be protected and have as short and direct a path to earth as practical. Arrester leads should

be as free from sharp bends as practical. The tanks of transformers and steel or aluminum structures may

be considered as the path for grounding arresters, provided effective connections can be made and

secure multiple paths are available. Where there can be any question regarding the adequacy of these

paths, it is recommended that a separate copper conductor(s) be used between the arrester ground terminal

and the substation grounding grid.

9.10.11 Investigation of Transferred Voltage

Transferred voltage contact may be considered a special case of the “touch” contact. A potential hazard

may result during a ground fault from the transfer of potentials between the ground grid areas and outside

points by conductors such as communication circuits, low-voltage neutral wires, conduit, pipes, rails,

metallic fences, etc. A person standing within the substation touches a conductor grounded at a remote

point, or a person standing at a remote point touches a conductor connected to the substation grounding

system. Here, the shock voltage may be essentially equal to the full voltage rise of the grounding system

under fault conditions and not the fraction of this total that is encountered in the usual “step” or “touch”

contacts.
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It is impractical and often impossible to design a grounding system based on the transferred voltage.

Hazards from these external transferred voltages are best avoided by using isolating or neutralizing

devices and by treating and clearly labeling these circuits, pipes, etc., as being equivalent to live lines.

Carefully examine the presence of any situations involving possible transferred voltage and take steps to

eliminate or avoid them. Clause 17.9 of IEEE Std. 80 discusses many such situations in greater detail.

9.10.12 Effect of Sustained Ground Currents

After the grounding design has been established as safe for the maximum ground fault current at the

appropriate clearing time, check step and touch voltages for sustained ground currents.

Sustained currents are those currents below the setting of protective relays that may flow for a long time.

Currents produced through the body as a result of these long-duration currents should be below safe let-go

values. Some sustained faults above the let-go current, but below the fibrillation threshold, may cause

asphyxiation from prolonged contraction of the chest muscles. However, it would not be practical to

design against lesser shocks that are painful but cause no permanent injury.

9.11 REFERENCES

Biddle Co., Getting Down-To-Earth, 5th ed. Trooper, Pa.: AVO International, 1998.

EPRI, Substation Maximum Earth Current Computation (SMECC).

IEEE Std. 80, “Guide for Safety in AC Substation Grounding.”

IEEE Std. 81, “Recommended Guide for Measuring Ground Resistance and Potential Gradients in Earth.”

IEEE Std. 81.2, “Measurement of Impedance and Safety Characteristics of Large, Extended or

Interconnected Grounding System (Part 2).”

IEEE Std. 837, “Qualifying Permanent Connections Used in Substation Grounding.”

RUS IP 202-1, “List of Materials Acceptable for Use on Systems of RUS Electrification Borrowers.”
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CHAPTER 10

INSULATED CABLES AND RACEWAYS

10.1 GENERAL

This chapter covers the application and selection of low-voltage, high-voltage, and special cables and

raceways for cable protection. Low-voltage cables are defined as those operating at 600 volts and below,

high-voltage as those operating above 600 volts, and special cables as those operating in the radio

frequency spectrum, i.e., 30 kHz and above.

See ANSI/IEEE Std. 525, “Guide for Selection and Installation of Control and Low-Voltage Cable

Systems in Substations,” for additional data on substation cables.

10.2 600-VOLT CABLE

10.2.1 Circuit Requirements

Circuits of 600 volts can be divided into two main categories: power circuits and control circuits.

Substation power circuits are those supplying power to cooling fans, insulating oil pumps, air

compressors, apparatus heaters, luminaires, and similar three-phase and single-phase loads. Voltage

levels and connections vary depending on the application. These can be:

1. 480/240 volt, three-phase delta connected

2. 480/277 volt, three-phase wye connected

3. 208/120 volt, three-phase wye connected

4. 240 volt, three-phase delta connected

5. 240/120 volt, three-phase closed or open delta connected with one phase center-tapped

6. 240/120 volt, single-phase three-wire

The relative merits of these six alternatives are covered in detail and illustrated in Chapter 15, AC and DC

Auxiliary Systems.

Substation control circuits are those that execute a command to and/or indicate the status of a piece of

apparatus such as a circuit breaker. Control circuits also include those concerned with currents and

voltages for relaying and similar purposes. These circuits usually operate at less than 300 volts and may

be dc or ac. Typical examples are current and potential circuits for protective relays and metering

devices, and trip or close commands to automatic protective devices. Communication and supervisory

control and data acquisition (SCADA) system circuitry fall under the category of control circuits.

In spite of the usually lower voltage level of control circuitry, a minimum insulation level of 600 volts

should be specified. Cable of 600 volts is more readily available than 300-volt cable, and the small, if

any, price differential is generally not an equitable trade for the additional protection provided by the

600-volt insulation. An exception to the above rule may be a requirement of several thousand feet of lowvoltage (48-volt) circuitry. In this instance, consider 300-volt insulation as a possible economic

advantage.
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10.2.2 Conductors

Insulated power and control circuit conductors of 600 volts may be copper or aluminum, solid or

stranded. Because of the lower termination reliability and lower ampacity of aluminum, copper is

generally preferred.

Power circuit conductors should be No. 12 AWG minimum size. Stranded conductors are easier to

handle and lend themselves to compression or bolted lugs and connectors. RUS Bulletins 50-71, “RUS

Specification for 600 V Underground Power Cable,” and 50-30, “RUS Specification for 600 V NeutralSupported Secondary and Service Drop Cables,” contain information on 600-volt power cables.

Control circuit conductors, because of low ampacity requirements, are often smaller than No. 12 AWG.

Stranding can be such as to permit flexibility. A typical No. 12 AWG control conductor could be made

up of 19 strands of No. 25 AWG copper whereas a power conductor would be made up of 7 strands of

No. 19 AWG.

Stranding of individual conductors is basically concentric and rope stranding. Concentric cable stranding

is defined as a cable consisting of a central wire surrounded by one or more helically laid wires with the

lay direction the same for all layers. A rope-stranded cable consists of groups of concentric cables.

Concentric cable has a more nearly circular cross section, permitting the best centering of the conductor

within the insulation. General-use 600-volt cable is manufactured concentric strand. Rope-stranded

power cable is available as flexible and extra flexible, and the cost is such as to preclude use for 600-volt

circuits. An exception would be the use of very short lengths of a large-diameter cable, where the

flexibility makes termination easier, or where excessive conductor movement is inevitable. Avoid such

situations if possible.

10.2.3 Conductor Configurations

Insulated conductors are manufactured as single- or multi-conductor cables, shielded or non-shielded, and

with or without armor.

Control circuit conductors are usually specified as multi-conductor cables. This has the basic advantage

of one specific multi-conductor circuit laying in one place instead of several places. This could be the

case with a four-conductor current transformer circuit.

10.2.3.1 Color Coding: Control circuit multi-conductor cables can be purchased with all wires

colored black or the wires color coded. Color coding should be by the Insulated Cable Engineers

Association (ICEA) methods.

Colored insulation compounds with tracers repeated in regular sequence (color coding) is the most widely

used method. Color coding methods are specified in ICEA Publication S-73-532/NEMA WC57, and the

color coding sequence shown in Tables E-1 and E-2 of that publication may be used, depending on the

application. Table E-1 is used when the installation is not required to meet NEC requirements. Table E-2

can be used for all installations, including those required to meet the NEC. The preferred method is

Table E-2, which is reproduced as Table 10-1.

Color coding for substation control circuits, even single conductor circuits, is recommended. Standard

codes can be established for circuit functions and individual wire functions. For example, a blue wire

standardized as a “trip” wire and a red wire standardized as a “close” wire for power circuit breaker

control duplicates the color practice for pilot lights on control panels indicating breaker status. In
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Table 10-1: Color Sequence. Ref. ICEA, App. E, S-73-532/NEMA WC57, Table E-2.

Conductor

Number

Background or

Base Color

Tracer

Color

Conductor

Number

Background or

Base Color

Tracer

Color

1 Black — 19 Orange Blue

2 Red — 20 Yellow Blue

3 Blue — 21 Brown Blue

4 Orange — 22 Black Orange

5 Yellow — 23 Red Orange

6 Brown — 24 Blue Orange

7 Red Black 25 Yellow Orange

8 Blue Black 26 Brown Orange

9 Orange Black 27 Black Yellow

10 Yellow Black 28 Red Yellow

11 Brown Black 29 Blue Yellow

12 Black Red 30 Orange Yellow

13 Blue Red 31 Brown Yellow

14 Orange Red 32 Black Brown

15 Yellow Red 33 Red Brown

16 Brown Red 34 Blue Brown

17 Black Blue 35 Orange Brown

18 Red Blue 36 Yellow Brown

addition, color coding can assist greatly in “ringing out” control circuits, especially in large substations.

It is recommended that, for additions to a non-coded substation, a color coding scheme be established for

the addition.

All-black control wires may be used for a strictly temporary control installation of minor size at the

option of the engineer.

Telephone and telemetering circuits where used should utilize the 25-pair-count color code method as

specified in ICEA Std. S-56-434, RUS Bulletin 1753F-205, “RUS Specification for Filled Telephone

Cables (PE-39),” and RUS Bulletin 1753F-208, “RUS Specification for Filled Telephone Cables with

Expanded Insulation (PE-89).” Except for lighting circuits, power conductor color coding need not be

used. Circuits can be tagged for phase indication and wire number after “ringing out.” Lighting circuit

conductors are specified single conductor with the neutral being white and a feed or switch wire black. It

is recommended that three-way switch dummy wires be coded red and blue, reserving green for a bonding

conductor where required.

10.2.3.2 Shielding: Conductor shielding of control circuit cables is specified basically to prevent a

false signal from being inductively coupled to a control circuit from an energized high-voltage bus or

from the switching operation of high-voltage disconnecting equipment, capacitor switching, coupling

capacitor voltage transformers, ground potential rise differences, and other switching-type operations. As

a general rule, a 230 kV or lower substation with electromechanical protective relays need not include

shielded control cables. However, if solid-state relays or supervisory remote terminal units are planned, a

study with reference to control cable shielding should be made. See ANSI/IEEE Std. 525, “Guide for

Selection and Installation of Control and Low-Voltage Cable Systems in Substations,” for additional

details.

Conductor shielding, where required for control circuit conductors, consists of a metallic covering

completely enclosing the conductor bundle. Individual conductor shielding is available but is not

applicable at 230 kV and below. Where shields are used, they should be grounded as outlined in Chap-
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ter 9, Grounding. For grounding methods that have been found to be effective in shielding control cables,

also see Chapter 9.

10.2.4 Conductor Insulation and Jackets

Insulation is a very important parameter in wire or cable selection. Base insulation selection on the

properties of life, dielectric characteristics, resistance to flame, mechanical strength and flexibility,

temperature capability, and moisture resistance. Insulation types applicable to substation conductors are:

• Ethylene Propylene Rubber EPR

• Cross-Linked Polyethylene XLPE

• Tree Retardant Cross-Linked Polyethylene TR-XLPE

The Oxygen Index (O.I.) of a plastic-insulated wire or cable is a measure of the fire propagation

resistance of the material as determined by the Fire Test of ANSI/IEEE Std. 422. Air normally contains

21 percent oxygen; hence, a material with an oxygen index below 21 will burn readily in air. A cable O.I.

of 27 or greater is generally high enough to pass the IEEE Fire Test.

Table 10-2 lists the basic properties of the insulating materials under consideration.

Table 10-2: Properties of Cable Insulating Materials

Material

Max. Oper.

Temp. °C (°F)

Oxygen

Index

Cost

(Low- ModerateHigh)

EPR 90 (194) 20 M

XLPE 90 (194) 18 M

TR-XLPE 90 (194) 18 M

Minimum acceptable insulation thickness shall be as specified by the RUS Bulletins 50-71, “RUS

Specification for 600 V Underground Power Cable,” and 50-30, “RUS Specification for 600 V NeutralSupported Secondary and Service Drop Cables.”

Since no single insulating material fulfills all requirements, engineering judgment is required for selection

of insulation for 600-volt substation wiring. Economic judgment should also be exercised as to

standardization.

The National Electrical Code (NEC) contains tables showing temperature ratings and location restraints

of insulation. The design engineer should also use the wealth of information available to him from cable

manufacturers’ data.

Jackets are used over individual insulated wires or over multi-conductor cables to provide protection

against mechanical damage, sunlight exposure, moisture, oil, acids, alkalis, and flame. Some insulating

materials used on single-conductor circuits, notably lighting circuits, have the required protection without

the use of additional jackets. An example is NEC Type TW, which is a 60°C, flame-retardant, moistureresistant thermoplastic insulation suitable for conduit, tray, or trench installation.

Jacket materials currently in use on 600-volt cables are Polyethylene and Polyvinyl Chloride (PVC).

Other jacket materials are also commercially available.
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10.2.5 Cable Sizing

In substation design, the important element of cable sizing is current carrying capacity. Voltage drop is a

secondary factor except for current transformer circuits, tripping circuits, and long conductor runs. Check

for voltage drop of the longest circuit, using the conductor size and the current capacity dictated.

Manufacturers’ data usually include voltage drop tables. Where such data are unavailable, calculate the

voltage drop. The voltage drop in a conductor should not be large enough to cause faulty operation of the

device being fed by the conductors. For power circuits, a 3 to 5 percent loss is tolerable with reasonable

regulation. Electric motors are generally rated for satisfactory operation at ±10 percent voltage; electric

heating elements will operate satisfactorily within the same range. If any doubt exists, contact the

equipment manufacturer to determine voltage tolerances applicable.

Also consider voltage drop in current transformer circuits. As can be seen from Figure 10-l, with a C400

transformer, No. 14 AWG leads are required. With a C200 transformer, No. 9 AWG leads are required.

In other words, calculate current transformer circuit voltage drop to select a cable size that allows the

current transformer ratio error to remain within acceptable limits. Given a certain current transformer

class furnished with equipment, the leads have to be sized for the given current transformer. A C200

current transformer can maintain 200 volts across the secondary terminals and hold the ratio error within

10 percent when 20 times full load current is applied.

Conductor selection based on current-carrying capacity is made by computing the current required to

serve the load. The wire or cable is selected from applicable Articles of the NEC or from manufacturers’

data. This applies to both control and power conductors. The NEC contains examples of branch and

feeder circuit size calculations.

The current-carrying capacity of a given size conductor is not a constant. The ampacity varies depending

on the installation condition. Conductors for use in free air are rated higher than those in conduit. More

than three conductors in a conduit also lowers the current-carrying capacity of each individual conductor.

In general, conductor insulation short-circuit capability for 600-volt substation service need not be

considered. As an example, No. 9 AWG copper with XLPE insulation may carry up to 5000 amperes for

2 cycles without conductor failure.

The cooperative should establish standard conductor sizes for the cooperative’s particular system, for

example, 4/c No. 9 for current transformer circuits, 5/c No. 12 for potential circuits, 8/c or 10/c No. 12 for

multipurpose control, and 1/c No. 12 for miscellaneous relay interconnections, etc. Standardization can

result in cost savings through quantity purchases and, if standard sizes are stocked, long lead times for

maintenance work can be eliminated.

10.2.6 Segregation of Control Cables

Low-voltage circuits providing instrumentation and control functions in a substation are subject to

failures and damage. The installation of these circuits to minimize damage, upon failure, to adjacent

circuits is one of the prime concerns in substation design. The cooperative should decide, based on

operating history, the substation voltage level where such damage may result in reduced reliability.
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Figure 10-1: Voltage Drop for Current Transformer Circuits

A method of approaching a solution to the possible damage situation is through circuit isolation or

segregation. This method approaches a solution because materials, methods, and costs dictate design

practices that may fall short of providing perfect isolation. The best design is a balance of reliability and

cost.

To prevent damage to adjacent cables, the following guidelines should be applied at least in 230 kV and

higher substations. Operating history may dictate use at 115 kV or lower substations.

a. Isolate circuits having the greatest exposure to primary voltage such as potential and current

transformer secondaries.

b. Group wiring from one power circuit breaker position and isolate it from other breaker

positions.

c. Group wiring from one bus differential.
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d. Group wiring from one transformer differential.

e. Route ac circuits on one side of a relay or control panel and dc circuits on the other side.

f. Group metering, alarm, and low-voltage (120-volt) control house circuits.

g. Divide trays with grounded metal barriers.

h. Where practical, run control cables perpendicular to high-voltage buses. If this is not possible,

maintain maximum physical separation.

i. Isolate primary protection circuits from secondary circuits or backup circuits.

Segregation of control cables also simplifies original circuit testing, maintenance procedures, and

substation additions and constitutes “good housekeeping.”

From these suggested guidelines and from operating history, the cooperative can establish control cable

segregation standards for its system. All substations on a system should be the same, promoting ease of

testing and maintenance and possibly an increase in reliability.

10.2.7 Installation Considerations

Cable failures occurring during precommission testing and/or shortly after substation service has begun

can often be traced to insulation failure caused by construction abuse or design inadequacy. Insulation

can be damaged by excessive pulling tension during construction. Conduit elbows selected with too

small a radius could result in insulation flattening during installation.

Bending radius for general-use power and control cables is dependent on insulation type, number of

conductors, size of conductors, and shielding. The cooperative should establish standards for its system

based on cable manufacturers’ recommendations.

Cable damage can also occur through the entry of moisture at an unsealed end. When a cut is made from

a reel, seal the reel end against moisture. Seal cable ends prior to connections. Lugs for use in moist

locations should be shrouded type.

Construction specifications should state that unlagged reels are not to be handled by lift trucks. Properly

store cable at all times to prevent damage. Common-sense handling by concerned personnel can prevent

cable damage both in storage and in the field.

Construction specifications should also require the following:

a. Wherever possible, cables need to be run from outdoor equipment to the control house without

splices.

b. Control cable splices should be made indoors at least 5 feet above the floor.

c. Taps and splices in trays should not be buried under other cables.

d. Splices should never be buried in earth or pulled in conduits or ducts.

e. Wires, splices, and taps in metal junction boxes should never be under cover pressure. An

adequately sized box should be specified.

f. Specifications and layouts should be designed to avoid sharp corners and also to provide

adequate space for pulling cables into place with a minimum of rigging.

Where relatively large conductors, #1/0 and above, are used in three-phase circuits, and the quantity

justifies it, consider ordering three or four conductors on a single reel. Such a consideration is an obvious

installation labor-saving decision.
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It is advisable, when a length is cut from a reel, that the new reel length be recorded. Inventory is

possible when this is done, and a project has less chance of delay because of lack of material control.

Cable terminations should allow enough slack to prevent tension on the terminating lugs.

10.3 POWER CABLE OVER 600 VOLTS

10.3.1 Medium-Voltage Shielded Power Cable (2 kV up to 35 kV)

The use of medium-voltage power cable for distribution circuits is generally limited to the underground

cables supplying power to the station service transformers, bus ties, and underground feeders that exit the

substation. Medium-voltage cables have solid extruded dielectric insulation and are rated from 1,000 to

35,000 volts. These single- and multiple-conductor cables are available with nominal voltage ratings of 5,

8, 15, 25, and 35 kV. Figure 10-2 illustrates the typical construction of medium-voltage shielded power

cable. RUS Bulletin 50-70, “RUS Specification for 15 kV and 25 kV Primary Underground Cable,”

contains additional information on 15 kV and 25 kV power cable.

Figure 10-2: Construction of Shielded Power Cable

10.3.2 Conductors

Medium-voltage power cable may be copper or aluminum with either a solid or stranded cross section.

The primary benefit of stranded conductors is improved flexibility. Stranded conductors can also be

compressed, compacted, or segmented to achieve desired flexibility, diameter, and load current density.

For the same cross-sectional area of a conductor, the diameter differs among solid and the various types

of stranded conductors. This consideration is important in the selection of connectors and in methods of

splicing and terminating. For the most part, stranded conductors are used almost exclusively for mediumvoltage power cable.

10.3.3 Conductor Shield

The conductor shield is usually a semi-conducting material applied over the conductor circumference to
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shield out the conductor contours. The shield prevents the dielectric field lines from being distorted by

the shape of the outer strands of the conductor. This layer also provides a smooth and compatible surface

for the application of the insulation.

10.3.4 Insulation

A very important parameter in cable selection is the insulation. Insulation selection should be based on

service life, dielectric characteristics, resistance to flame, mechanical strength and flexibility, temperature

capability, and moisture resistance. Common insulation types applicable to medium-voltage cables are:

• Ethylene Propylene Rubber EPR

• Cross-Linked Polyethylene XLPE

• Tree Retardant Cross-Linked Polyethylene TR-XLPE

EPR and TR-XLPE are the most common insulating compounds for medium-voltage power cables.

Minimum acceptable insulation thickness shall be as specified by the RUS Bulletin 50-70, “RUS

Specification for 15 kV and 25 kV Primary Underground Power Cable.” The NEC contains tables

showing temperature ratings and location restraints of insulation types. Also use the wealth of

information available from cable manufactures’ data.

Since no single insulation material fulfills all requirements, engineering judgment is required for selection

of insulation for medium-voltage cable. Also factor in the economics of cable standardization.

10.3.5 Insulation Shield

The insulation shield is a two-part system composed of an auxiliary and a primary shield.

An auxiliary shield is usually a semi-conducting nonmetallic material over the insulation circumference.

It has to be compatible with the insulation. A commonly used auxiliary shield consists of an extruded

semi-conducting layer partially bonded to the insulation. The primary shield is a metallic shield (wire or

tape) over the circumference of the auxiliary shield. It has to be capable of conducting the sum of

“leakage” currents to the nearest ground with an acceptable voltage drop. In some cases it also needs to

be capable of conducting fault currents. The shield has several purposes:

• Confine the electric field within the cable.

• Equalize voltage stress within the insulation, minimizing surface discharges.

• Protect cable from induced potentials.

• Limit electromagnetic or electrostatic interference (radio, TV etc.).

• Reduce shock hazard (see Chapter 9 for proper grounding of the shield).

10.3.6 Jackets

The cable may have components over the insulation shielding system to provide environmental

protection. This material can be an extruded jacket of synthetic material, metal sheath/wires, armoring, or

a combination of these materials. Selection of jacket material should be based on the conditions in which

the cable will be operated. The following considerations should be taken into account:

• Service life

• Temperature capability
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• Requirements for mechanical strength and flexibility

• Abrasion resistance

• Exposure to sunlight, moisture, oil, acids, alkalis, and flame

A common jacket type applicable to medium-voltage cable is:

• Linear Low Density Polyethylene LLDPE

Since no single jacket material fulfills all requirements, engineering judgment is required for selection of

a jacket for medium-voltage cable. Also factor in the economics of cable standardization.

10.3.7 Cable Voltage Rating

The voltage rating of a cable is based, in part, on the thickness of the insulation and the type of the

electrical system to which it is connected. General system categories are as defined by the Association of

Edison Illuminating Companies (AEIC).

10.3.7.1 100 Percent Level: Cables in this category may be applied where the system is provided

with protection such that ground faults will be cleared as rapidly as possible, but in any case within 1

minute. While these cables are applicable to the great majority of cable installations on grounded systems,

they may also be used on other systems for which the application of cables is acceptable, provided the

above clearing requirements are met when completely de-energizing the faulted section.

10.3.7.2 133 Percent Level: This insulation level corresponds to that formerly designated for

ungrounded systems. Cables in this category may be applied in situations where the clearing time

requirements of the 100 percent level category cannot be met, and yet there is adequate assurance that the

faulted section will be de-energized in one hour or less. They may also be used when additional

insulation thickness over the 100 percent level category is desirable.

10.3.7.3 173 Percent Level: Cables in this category should be applied on systems where the time

required to de-energize a grounded section is indefinite. Their use is also recommended for resonant

grounded systems. Consult the cable manufacturer for insulation thickness.

10.3.8 Conductor Sizing

In substation applications, the most important element of cable sizing is the current-carrying capacity that

is required to serve the load. Take into account both continuous and non-continuous loads and any

emergency overload that the cable will be required to carry. Voltage drop is a secondary factor in very

large installations with long cable runs. Check for voltage drop of the longest circuit, using the conductor

size and the current capacity indicated. Manufacturers’ data include voltage drop tables. Where such

data are not available, calculate voltage drop. The voltage drop in a conductor should not be large enough

to cause faulty operation of the device being fed by the conductors. For medium-voltage circuits, 3 to

5 percent regulation is generally tolerable with reasonable regulation. If any doubt exists, contact the

equipment manufacturer to determine the applicable voltage tolerances.

Conductor selection based on current-carrying capacity is made by computing the current required to

serve the load. Select the cable from the applicable articles of the NEC and the manufacturers’ data. The

current-carrying capacity of a given size conductor varies depending on the cable installation (in air,
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underground, conduit, cable tray etc.). Make sure the correct articles and tables in the NEC are applied

when sizing the cable for current-currying capacity for the cable installation being considered.

Also take into account the available three-phase and phase-to-ground fault current levels when selecting

the conductor size and shield requirements. In some cases, the minimum size conductor determined by

the fault current level requirements would result in a larger conductor size than was determined by the

load current-carrying requirements.

After calculating the available fault current levels and time required to clear the fault, look at the cable

manufacturer’s data to determine the minimum size conductor and shield requirements for the application.

10.3.9 Terminations and Splices

Cable terminations are required for cables 1 kV and above. When shielded power cables are terminated

and the insulation shield is removed, an abrupt change in the dielectric field results. Consequently, there

is a concentration of electrical stresses along the insulation surface at the point where the shielding ends.

These non-uniform stress concentrations can cause insulation breakdown and cable failure.

To prevent cable failure, the cable has to be terminated in such a way as to eliminate the non-uniform

voltage stresses. This is accomplished by placing a stress cone over the cable insulation. The stress cone

has to be prefabricated.

Shielded power cables terminated indoors or in a controlled environment require only a stress relief cone.

When a cable is terminated outdoors, it is exposed to various contaminants, many of which are conductive

and/or corrosive. These contaminants may cause flashover or arcing from the insulated conductor to the

nearest adjacent conductor. This would result in degradation of the termination. Therefore, extended

creep path is required in addition to stress relief when terminating shielded power cable outdoors. This is

accomplished by adding skirts to the termination to increase the creepage distance.

Splices are mainly used when it is necessary to join two cables at manholes and pull boxes. The basic

concept to be remembered in splicing two cables is that the cable splice is in fact a short piece of cable

that is fabricated in the field. As such, the splice needs to have the same components as the cables. For

shielded cables, the design of the splice needs to be compatible with the cable materials and also provide

the continuation of each cable component in order to keep voltage stresses to a minimum.

Currently, prefabricated termination kits and splice kits are the preferred practice because of the savings

in time and materials.

10.3.10 Cable Segregation

According to the NEC, medium-voltage power cables should be segregated from low-voltage power,

instrument, and control circuits. See the applicable articles in the NEC for additional information.

10.3.11 Installation Considerations

The type of medium-voltage power cable selected should be suitable for all environmental conditions that

occur in the area where the cable is installed. Prior to purchase and the actual installation of the cable,

consider the following:
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• Cable operating temperatures in substations are normally based on 40°C ambient air, or 20°C

ambient earth temperature. Give special consideration to cable installed in areas where

ambient temperatures differ from these values.

• Whether the cable is direct buried; installed in duct banks, below-grade conduits, or trenches;

or installed in above-grade cable trays or conduits, the cable should be rated and UL approved

for the particular cable installation. The cable should also be suitable for operation in wet and

dry locations. If in doubt about the application, consult the cable manufacturer.

• The service life of the cable selected in most cases should be at least equal to the design life of

the substation.

• Cables installed in cable trays or other raceway systems where flame propagation is of concern

should pass the UL Std. 1072 or ANSI/IEEE Std. 383 flame tests.

• The cable should maintain its required insulating properties when exposed to chemical

environments.

Cable failures occurring during pre-commission testing and/or shortly after substation service has begun

can often be traced to insulation failure caused by construction abuse or design inadequacy. Insulation

can be damaged by excessive pulling tension or by exceeding the minimum bending radius during

construction. The bending radius depends on insulation type, number of conductors, size of conductors,

and type of shielding. The cooperative should establish standards for the system based on the cable

manufacturers’ recommendations.

Cable damage can also occur through the entry of moisture at an unsealed end. When a cut is made from

a reel, seal the reel against moisture. Seal cable ends prior to termination.

10.3.12 High-Voltage Power Cable (69 kV up to 230 kV)

Underground transmission cable usage in the United States is very small: less than 1 percent of overhead

line mileage. The highest underground cable voltage that is commonly used in the United States is 345

kV, and a large portion of this cable is high-pressure fluid-filled pipe-type cable. Extruded dielectric

cables are commonly used in the United States up to 230 kV, with up to 500 kV in service overseas.

Underground transmission cable is generally more expensive than overhead lines. Because of all the

variables (system design, route considerations, cable type, raceway type, etc.), it has to be determined

case by case if underground transmission cable is a viable alternative. A rule of thumb is that

underground transmission cable will cost from three to twenty times the cost of overhead line

construction. As a result of the high cost, the use of high-voltage power cable for transmission and

subtransmission is generally limited to special applications caused by environmental and/or right-of-way

restrictions. For this reason, few applications will be justified for the cooperative’s system. If

underground transmission cable is going to be considered, an engineering study is required to properly

evaluate the possible underground alternatives.

See EPRI’s Underground Transmission Systems Reference Book for additional information on highvoltage power cable.

10.4 SPECIALIZED CABLE

Substation cable in this category consists of coaxial cables for low-frequency (30 kHz to 500 kHz) use in

carrier communications and for ultra-high-frequency (300 MHz to 3 GHz) use in microwave systems.
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Coaxial cables for carrier communications are available with surge impedance (Zo) of 50 and 75 ohms,

50 ohms being the most common. Because of the low power requirements of carrier systems, cable

power rating need not be considered. The primary consideration is jacket material. Some jackets contain

plasticizers that, when exposed to weather, leach into the center insulator, seriously increasing power

losses and making replacement necessary in approximately five years.

Non-contaminating jackets are available where the life of the jacket is 20 years or more. The cost

differential of a few cents per foot is worth the added reliability.

Typical coaxial cable for carrier communication use is RG-213/U having a non-contaminating jacket and

nominal Zo of 50 ohms, but, depending on the application, a different coaxial cable may be required.

Coaxial cable for microwave communication (3.0 GHz and below) is a part of a more sophisticated

system. Losses and power rating should be taken into consideration.

Microwave coaxial cable, 50 ohms Zo, is available with air dielectric and foam dielectric. Air dielectric

cable, to prevent moisture entry, is pressurized with inert gas, usually nitrogen. At a given frequency,

cable with air dielectric has less attenuation than with foam dielectric, but the pressure system has to be

monitored. Foam dielectric is the preferred cable. The transmitter may have to be specified with power

to overcome the cable attenuation, but this can be minimized with attention to equipment location and by

keeping coaxial leads short. A detailed selection procedure for microwave cable is covered in

manufacturers’ handbooks.

If spectrum space below 3.0 GHz is unavailable, the cooperative wishing to use microwave

communications may have to apply for a higher frequency. Above 3.0 GHz, coaxial cables exhibit far too

much attenuation for practical use, necessitating use of wave guides. Wave guide application is beyond

the scope of this bulletin.

10.5 RACEWAYS

10.5.1 Function

Raceways, in the form of conduits, trays, and trenches, are used in substations to provide protection and

electrical segregation of cables.

Historically, raceway materials evolved as materials evolved, brought on mainly by increasing labor

costs. Steel conduit was followed by fiber and cement asbestos conduit. The lower weight and easier

tooling was the main advantage. Block trenches and cast-in-place concrete trenches followed. These

trenches, while about the same cost as concrete-encased ducts, reduce the potential for cable damage

since the cables are simply laid in the trench. Precast concrete trench, knocked down for field assembly,

then became available. Plastic conduit followed and is a stock item with many electrical suppliers. Other

materials for raceway use will likely appear on the market.

10.5.2 Economics

The economics of a raceway system for a substation hinge on a cost/benefit ratio. A balance between

required reliability and the cost of such reliability should be established.

The design costs of various systems generally will not vary appreciably. More design will be required for

an underground duct system than would be required for precast trench for a large substation.
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Delivery charges to the site for various materials, site handling costs, and installation labor costs are the

major items to be considered in an economic evaluation. Simplicity of expansion, ease of testing,

maintenance and cable replacement, personnel safety, security, and appearance may, in part or in total, be

factors for consideration when alternative systems are being studied.

In addition to items discussed in this guide, use the many available trade publications as necessary.

10.6 UNDERGROUND RACEWAYS

Since all underground systems offer the same “out-of-the-way” appearance and the same degree of

security, these criteria are irrelevant when comparing one system to another.

In this guide, the use of underground metallic conduit for other than 1⁄2- and 3⁄4-inch lighting circuits is not

considered. Labor and material costs prohibit such an installation.

Underground methods available are:

a. Direct-buried cable

b. Direct-buried conduit

c. Concrete-encased conduit (duct bank)

d. Cable trenches (partially underground)

10.6.1 Direct-Buried Cable

Direct-buried cable, although the least costly underground method, should generally be avoided except

for lighting branch circuits, and then only in small installations. Circuit reliability can be continually

threatened by excavation. Metallic armored cables can minimize this damage and potential personnel

hazard but sacrifice the lower cost.

Most control and power cables, with insulation suitable for any below-grade installation, are suitable for

direct burial. However, without a surrounding case (conduit), the cables are subject to damage by

burrowing animals.

Trenches for direct-buried cables are shown in RUS Bulletin 1728F-806, “Specification and Drawings for

Underground Electric Distribution” drawings UR2 to UR2-2, UR2-3 to UR2-5, UR2-NT and UR2-ST

inclusive.

Advantages

a. The width of the excavation is minimized.

b. Cable can be laid in with no pulling damage.

c. Conduit labor and material cost are at a minimum (only equipment risers are required).

d. “In-line” handholes or manholes are not required.

Disadvantages

a. Testing is done prior to backfilling the trench, leaving cable exposed to potential damage.

b. “Dig-in” damage is possible.
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c. Trench bottom and backfill material has to be carefully inspected. Original excavated material

may be unsatisfactory for backfill, requiring purchase and delivery of proper material.

d. Electrical circuit segregation, without separate or wide trenches, may not be possible.

e. Cable replacement or cable additions require additional excavation.

f. Neutral corrosion is possible.

10.6.2 Direct-Buried Conduit

In a small distribution substation, direct-buried nonmetallic conduit for control and power cable including

lighting circuits should offer the most economical underground system or cost/benefit ratio.

Select non-metallic conduit with a wall thickness suitable for direct earth burial. Procure fittings for the

conduit, whether plastic, fiber, or cement asbestos, from the manufacturers of the conduit. This will

ensure component compatibility.

Except for equipment risers, avoid conduit bends to limit cable pulling tension. Pulling tension should be

limited to 454 kg (1000 lbs) when pulled with a basket grip. Control cables with conductors No. 16

AWG and smaller should be limited to 40 percent of this value or lower if recommended by the

manufacturer.

In the design phase, calculate conductor pulling tension using Equation 10-1:

Equation 10-1

Where:

T = Tension, in kilograms (pounds)

l = Length of conduit run, in meters (feet)

w = Unit weight of cable, in kilograms/meter (pounds/foot)

f = Coefficient of friction (0.5) (f may be decreased by using pulling lubricants)

Use this relation in the computation and compare the worst case to the maximum allowable tension.

Reduce excessive lengths with handholes or manholes to provide pulling points.

Use Equation 10-1 to determine the pulling tension for a given conduit length. Given the tension, the

maximum length (L) can be found using Equation 10-2:

Equation 10-2

Direct-buried conduit banks can be installed in the same way as concrete encased (see Section 10.6.3) less

the concrete. The cable derating factors discussed in Section 10.6.3 have to be applied.

Advantages

a. “Dig-in” damage is reduced.

b. Excavation, conduit placement, and backfilling can be one operation.

c. Electrical circuit segregation is possible.

d. Burrowing animal damage to cable is prevented.

e. Expansion is eased.

T = lwf

L = T/wf
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f. Cable replacement is eased.

Disadvantages

a. Cables are pulled; hence, care is required to prevent damage.

b. Manholes or handholes may be required.

c. Backfill material requires inspection as to suitability.

10.6.3 Concrete Encased Conduit (Duct Bank)

Concrete-encased duct bank is decreasing in popularity, giving way to cable trenches. In spite of the

growing popularity of cable trench use in substations, cases exist where duct banks have to be used, either

with or without concrete encasement. Cases in point could include conduits passing under heavy traffic

roads, posing a barrier to equipment movement, or blocking natural drainage. Resolve this or similar

situations when determining the preferred raceway system.

When several cables are placed in the same duct bank, the operating temperature of the inner cables could

exceed the safe operating temperature of the cable insulation. To prevent this situation, the currentcarrying capacity of the cable is de-rated, based on the NEC. Make sure the correct articles and tables of

the NEC are applied when determining the current-carrying capacity for concrete-encased duct bank

installations. The engineer can change the current-carrying capacity of the cable significantly by

selecting different duct bank configurations and spacing, etc.

The ampacity values indicated in the NEC tables were calculated as detailed in “The Calculation of the

Temperature Rise and Load Capability of Cable Systems” by J.H. Neher and M.H. McGraph. The NEC

Ampacity Tables cover most applications, but if the duct bank configuration, spacing, etc., is not included

in the NEC Ampacity Tables, calculate the duct bank ampacity of the cable by using the Neher and

McGraph method. Either do the calculations by hand or use one of the many available computer

programs.

To determine the approximate duct bank ampacity of the cable, calculate it by multiplying the normal

ampacity or load of the cable by a position factor. Figure 10-3 cites examples of these position factors.

For an underground installation, excavation work should be specified as called for in Chapter 6. The

designer should indicate a pitch of 10.2 centimeters per 30.5 meters (4 inches per 100 feet) for duct

drainage.

There are two types of duct bank: built up and tier. The built-up (monolithic) method consists of laying

conduits on fabricated plastic spacers, sized to the conduit outside diameter and desired separation. Base

spacers allow for 7.6 centimeters (3 inches) of concrete below the bottom row of conduits (ducts).

Intermediate spacers are placed on the top of the bottom and succeeding layers of ducts to the desired

height. Spacers are placed on both sides of couplings, the couplings being staggered along the run. When

the entire bank is constructed and inspected to ensure ducts are aligned and continuous, the entire duct

bank is enclosed with machine-mixed concrete grout, usually a 1:6 mix. The monolithic pour of the builtup method is usually used with very careful supervision of all steps to eliminate the faults prevented by

tiering. Figure 10-4 illustrates monolithic duct bank construction.
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Figure 10-3: Duct Bank Position Factors
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Figure 10-4: Monolithic Duct Bank Construction

The tier method consists of placing a 7.62 cm (3-inch) layer of concrete in the bottom of the trench. After

an initial set, the bottom row of ducts is laid with separation maintained by wooden or metal combs with

the crossbar thickness equal to the required vertical separation. Concrete is poured, screened to the comb

tops. After partial set, the combs are removed and the process repeated to the full height of the duct bank.

Figure 10-5 lists the amount of concrete required for various duct combinations. The tier method is

obviously more costly, but concrete voids, duct separation, and duct floating are prevented.

Advantages

a. Permanent

b. Improbable accidental cable damage by “dig-in”

c. Ease of cable replacement

d. Possible electrical circuit segregation

e. Impossible burrowing animal damage
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Figure 10-5: Tier Duct Bank Construction Cubic Yards of Grout for 100 Trench Feet
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Disadvantages

a. Cost

b. Consideration of substation expansion

c. Required derating of certain cables in large duct banks

10.6.4 Cable Trenches

The most significant advantage of cable trench use is the saving of labor during cable installation plus the

absence of cable pulling damage. Trenches are becoming the most acceptable cable installation method,

particularly in large installations.

Cable trenches may be constructed in several ways.

10.6.4.1 Block Construction: If block construction is planned for a control house, economics may

indicate block trench. Core or solid, concrete or cinder block is satisfactory for cable trench. Covers can

be fabricated from checkered plate aluminum or lightweight concrete. Figure 10-6 illustrates suggested

construction.

10.6.4.2 Cast-in-Place Concrete Construction: This form of trench construction can be justified in a

large substation where many foundations are being constructed and the necessary tradesmen and materials

are readily available. Fabrication is similar to the block cable trench illustrated in Figure 10-6.

10.6.4.3 Precast Concrete Trench: Depending on manufacturing plant locations and related freight

cost, precast trench may present an attractive alternative for a reasonably large installation. Field labor

should be substantially lower than the block or cast-in-place options. Precast trench is supplied with

lightweight concrete covers in manageable lengths, depending on trench width. Figure 10-7 shows a

typical design. Transitions are also available for vehicular crossings and building entrances.

A very high degree of layout flexibility is available to the engineer. Direction changes are usually limited

to 90°, but, with the cable lay-in benefits, cable damage in construction should be nonexistent. The

engineer can, with different trench widths, lay out a complete trench system without costly manhole

construction, also avoiding substation roadways.

Electrical segregation cannot be as complete with a cable trench system as in a multiple-conduit duct bank

system. In general, cable trenches are constructed without bottoms or floors. This is done to eliminate

floating or frost heaving with consequent possible misalignment. Cables are placed on a 10.2- to

15.2-centimeter (4- to 6-inch) bed of fine sand. French drains can be placed at selected intervals to drain

the trench of stormwater.

Advantages

a. Cable is laid in.

b. Cable replacement or addition is simplified.

c. Expansion is unlimited.

d. Electrical segregation is possible to a limited degree.

e. Layout does not require manholes.

f. A high degree of installation flexibility is possible.
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Figure 10-6: Block Trench, Cast Concrete Similar

Disadvantages

a. It does not prevent cable damage from burrowing animals and rodents.

b. Care has to be exercised to prevent covers from falling into the trench and damaging cable.

c. Vehicular traffic over trenches has to be prevented.

d. It can be a possible drainage barrier.
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Figure 10-7: Pre-cast Cable Trench

10.6.5 Manholes

A companion item to some underground raceway systems is the manhole. Generally used in conjunction

with below-grade duct banks, a manhole serves as a pulling and splicing point for cable runs, as a point to

turn a duct line, and as a place to provide contraction and expansion of power conductors.

In light of the high construction costs even with precast units, and the ease of design and substantially

lower cost of a total trench design, details of manholes will not be considered in this guide.

10.6.6 Handholes

Unlike manholes, handholes have a definite place in substation design. A handhole is essentially a

miniature manhole installed approximately 0.61 meter (2 feet) below grade and measuring about 0.37

meter square (2 feet square). It serves as a pulling point for cables in a direct-burial conduit system. To
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prevent floating, no bottom or floor is provided. This feature also allows easy conduit entry. A split

metal cover or a lightweight concrete cover with knockouts is recommended.

The cooperative, depending on handhole usage, may elect to design forms and produce handholes. An

outside small business firm could also be contracted to perform this service.

Figure 10-8 shows a suggested handhole design the cooperative can size to its particular requirements.

Figure 10-8: Suggested Handhole Design

10.7 RACEWAY COMBINATION

In all but the simplest installation, the designer will be confronted with combinations of the below-grade

systems outlined in this chapter. Such combinations are the usual practice in substation design.

The specific combinations used in a given substation could possibly vary by geographic location. The

most common system is one using cable trench, direct-buried conduit, handholes, and conduit rises.

Figure 10-9 shows a typical system.
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Figure 10-9: Trench to Handhole Conduit Installation

10.8 SUMMARY—UNDERGROUND RACEWAYS

If direct-buried cable is under consideration for a small installation, it should be recognized that a treated

plank over the cable can offer some cable protection. Additionally, markers are available to indicate the

cable route. The best protection against accidental dig-in is to maintain accurate, up-to-date drawings and

set up a control system for all excavation within a substation enclosure.

Precast concrete duct sections are available under various trade names. These products make excellent

raceways. However, determine site handling costs since the weights of the raceway components are high.

The concrete-encased duct system will find limited use in all but the very largest substations, and then

under heavy axle-bearing roads. Heavy-wall, direct-burial, PVC conduit, 91.44 cm (36 inches) below a

substation road surface will successfully withstand most substation vehicular traffic, depending on soil

conditions.

The possibility of burrowing animals causing cable damage in trenches has been mentioned. With a

knowledge of the area, take this situation into account when selecting site surface stone size and depth.

The animal problem can be eliminated with adequate surface preparation. For guidance, see CRN’s

Animal-Caused Outages (Project 94-5).

Trapping or low points of below-grade conduits should be avoided in the design phase.

Make use of the many handbooks and other material available from vendors of raceway materials.

10.9 OVERHEAD RACEWAYS

In cases where buried raceway systems are impossible or unnecessary, above-grade raceways can be

considered.

Available overhead raceways are:
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a. Cable tray

b. Cable duct

c. Plastic conduit

d. Metal conduit

e. Above-grade cable trench

10.9.1 Cable Trays

Cable trays offer ease of installation and circuit segregation within one tray. Pay attention to mounting

details to prevent weather damage. Substation structures and/or specially designed support structures can

be used.

Specify solid-bottom tray with expanded metal covers to prevent bird nesting. Consider access for

equipment removal in the design phase.

10.9.2 Cable Duct

Cable duct consists of cable tray fitted with wooden blocks to properly space and support power

conductors, in the 600- to 15000-volt range. Application in a substation would be limited to incoming or

exiting distribution circuits.

10.9.3 Plastic Conduit

Plastic conduit and fittings are available from several manufacturers to meet the requirements of the NEC.

Installation of this conduit has a labor advantage over steel since 4-inch steel weighs 14.9 kilograms per

meter (10 pounds per foot) as compared to plastic weighing 3.0 kilograms per meter (2 pounds per foot).

An adequate variety of fittings and bends is available, and joining is done with a cement. Threading is

not required. Support requirements are outlined in the NEC.

10.9.4 Metal Conduit

Metal conduit comes in three types: electrometallic tubing (thin wall), galvanized steel (heavy wall), and

aluminum.

Thin wall is limited to 2 inches in diameter, and fittings are expensive. The 2-inch size weighs

0.21 kilograms per meter (0.14 pounds per foot) as compared to 4.9 kilograms per meter (3.3 pounds per

foot) for steel. Gland-type fittings are available to provide weather tightness.

Galvanized steel conduit, available in trade sizes from 1⁄2 to 6 inches, will provide the best mechanical

protection for control and power cables. However, labor cost is high. Cutting, threading, and bending

require tools not usually owned by tradesmen. The best application in a substation for this conduit is for

serving lighting and convenience outlets with conduit clamped to structural members. Outdoor fittings

and luminaires are threaded for 1⁄2- and 3⁄4-inch rigid conduit. Aluminum conduit offers weight advantage

in large sizes. Additionally, if each phase is installed in a separate conduit, aluminum will not heat up as

will steel. Aluminum conduit should not be installed below grade, either for direct burial or concrete

encasement, because of possible corrosion damage.
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10.9.5 Above-Grade Cable Trench

A cable trench of block, cast-in-place, or precast concrete construction is satisfactory for above-grade

raceways. Construction would be identical to a below-grade trench. In the case of precast construction,

the “bracket” would have a 1⁄2-inch threaded insert, and the sidewalls each would have a half hole on each

end. A 1⁄2-inch bolt and square washer would hold the wall in place in lieu of backfill. This construction

method is not recommended where ground is subject to severe frost movement.

10.10 SUMMARY—OVERHEAD RACEWAYS

Where underground cable placement is not possible and substation control is sophisticated, cable tray

anchored to the substation equipment supports and/or above-grade trestles should be considered. The tray

could be selected to provide circuit segregation. Grounding of non-current-carrying metal parts such as

exposed cable tray is necessary and is covered in Chapter 9.

In the simplest temporary substation, plastic conduit would require the least labor time. Under some

conditions, the conduit could be installed on top of the site stone.

10.11 RACEWAY MATERIALS

10.11.1 Plastic

Plastic conduit, as currently available, covers an extensive list of organic materials with a variety of wall

thicknesses, degrees of flexibility, available lengths, diameters, and applications.

For duct types, characteristics, and applications, see the appropriate NEMA standard or manufacturers’

data. This information should include the codes and standards met by the listed conduit types.

10.11.2 Fiber

Fiber conduit is a smooth-bore duct made of wood pulp pressure felted on a rotating mandrel, dried, and

vacuum impregnated with hard coal tar pitch. The ends of 8-foot lengths are tapered, as are couplings.

Cutting can be done with a coarse-tooth hand saw, and a factory-quality taper is easily accomplished with

a tapering tool.

The material is manufactured with wall thickness for direct burial or concrete encasement. Angle

couplings, bends, and offsets are available. Adapters for joining to threaded steel, reducers, and caps are

stock items with many distributors.

Manufacturers’ data and detailed installation instructions are easily obtained.

10.12 RACEWAY SIZING

Raceway sizing is an important parameter in substation design, particularly for a large installation. When

laying out the underground system, it is important to visualize the station as it will be as expanded,

possibly to the ultimate configuration.

In sizing individual conduits of the system, good practice indicates 40 percent maximum fill for each

conduit. This means the total cross-sectional area (over insulation) of all conductors in a conduit should
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not exceed 40 percent of the cross-sectional area of the interior of the conduit or duct. As an example, a

4-inch conduit has an internal area of 12.72 square inches; hence, at 40 percent fill, the total conductor

area should not exceed 5.09 square inches. This practice is allowed by the NEC and refers to single ducts.

In the planning stages, the ultimate substation has to be visualized and duct banks sized to provide for all

required cables, remembering that all substation control cables originate at the control house. Duct exits

should be provided for ultimate requirements.

It was previously noted that underground duct bank application is decreasing in substation expansion and

new substation design, giving way to cable trenches. When the uncertainties of below-grade duct bank

design for a future expansion program are considered, cable trench becomes a viable alternative.

The NEC outlines the sizing of cable tray. The same article can be used as a guide for cable trench sizing.

The limits in the article can be exceeded within reason because the trench will be located outdoors with

normally lower ambient temperatures than for indoor tray.

10.13 REFERENCES

ANSI/IEEE Std. 383, “Type Test of Class 1E Electric Cables, Field Splices and Connections for Nuclear

Power Stations.”

ANSI/IEEE Std. 422, “Design & Installation of Cable Systems in Power Generating Stations.”

ANSI/IEEE Std. 525, “Guide for Selection and Installation of Control and Low-Voltage Cable Systems in

Substations.”

ASTM Std. B3, “Soft or Annealed Copper Wire.”

ASTM Std. B8, “Concentric-Lay-Stranded Copper Conductors, Hard, Medium-Hard, or Soft.”

ASTM Std. B33, “Tinned Soft or Annealed Copper Wire for Electrical Purposes.”

ASTM Std. B172, “Rope-Lay-Stranded Copper Conductors Having Bunch-Stranded Members, for

Electrical Conductors.”

ASTM Std. B189, “Lead-Coated and Lead-Alloy-Coated Soft Copper Wire for Electrical Purposes.”

Electric Power Research Institute, “Underground Transmission Systems Reference Book,” Report

TR-101670, March 1993.

ICEA Std. P-46-426, “ICEA Power Cable Ampacities Copper and Aluminum Conductors.”

ICEA Std. S-19-81, “Rubber-Insulated Wire and Cable for the Transmission and Distribution of Electrical

Energy.”

ICEA Std. S-56-434, “PE Insulated Communication Cables.”

ICEA Std. S-61-402, “Thermoplastic-Insulated Wire and Cable for the Transmission and Distribution of

Electrical Energy.”
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ICEA Std. S-66-524, “Cross-Linked-Thermosetting-Polyethylene-Insulated Wire and Cable for the

Transmission and Distribution of Electrical Energy.”

ICEA Std. S-68-516, “Ethylene-Propylene Rubber Insulating Wire and Cable for the Transmission and

Distribution of Electrical Energy.”

ICEA Std. S-73-532/NEMA WC57, “Standard for Control Cables.”

IEEE Std. 48, “Test Procedures and Requirements for High-Voltage Alternating-Current Cable

Terminations.”

IEEE Std. 141, “Recommended Practice for Electric Power Distribution for Industrial Plants.”

IEEE Std. 404, “Cable Joints for Use with Extruded Dielectric Cable Rated 5,000 Through 46,000 Volts,

and Cable Joints for Use with Laminated Dielectric Cable Rated 2,500 Through 500,000 Volts.”

IEEE Std. 575, “Guide for the Application of Sheath-Bonding Methods for Single-Conductor Cables and

the Calculation of Induced Voltages and Currents in Cable Sheaths.”

Neher, J.H., and M.H. McGraph, “The Calculation of the Temperature Rise and Load Capability of Cable

Systems,” AIEE Paper 57-660.

NFPA Std. 70, National Electrical Code.

RUS Bulletin 1728F-806, “Specification and Drawings for Underground Electric Distribution.”

RUS Bulletin 1753F-205, “RUS Specification for Filled Telephone Cables (PE-39).”

RUS Bulletin 1753F-208, “RUS Specification for Filled Telephone Cables with Expanded Insulation

(PE-89).”

RUS Bulletin 50-30, “RUS Specification for 600 V Neutral Supported-Secondary and Service Drop

Cables”

RUS Bulletin 50-70, “RUS Specification for 15 kV and 25 kV Primary Underground Power Cable”

RUS Bulletin 50-71, “RUS Specification for 600 V Underground Power Cable”

UL Std. 44, “Rubber-Insulated Wires and Cables.”

UL Std. 83, “Thermoplastic-Insulated Wires and Cables.”

UL Std. 854, “Service Entrance Cables.”

UL Std. 1072, “Medium-Voltage Power Cables.”

UL Std. 1277, “Electric Power and Control Tray Cables with Optional Optical-Fiber Members.”
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CHAPTER 11

CORROSION

11.1 GENERAL

Corrosion is the deterioration of a metal by chemical or electrochemical reaction with its environment.

The basic reason for corrosion problems in and around the substation grounding grid is electrochemical in

nature.

11.1.1 Characteristics of Corrosion

The way in which corrosion affects underground structures varies depending on the mechanism and

circumstances. In general, there are two types of corrosion. One is the general metal loss in which the

entire surface of the metal exposed to the soil in a given area is corroded away. Typical of this is the

general thinning of strands on a concentric neutral cable throughout the area. The second type of

corrosion is localized or “pitting”-type corrosion. In this form, very local areas of metal are attacked while

the metal immediately adjacent remains untouched. This type of corrosion can also be found on

concentric neutral cables. It generally results in the breakage of many of the individual strands of the

neutral, rendering it disconnected and either useless or significantly reduced.

The important difference between local pitting corrosion and general metal loss is that it takes very little

metal loss of the local pitting type of corrosion to cause a complete loss of continuity in a neutral wire or

to penetrate a pipe wall or lead sheath. Therefore, local pitting-type corrosion is more serious to the

power industry.

The substation grounding grid corrosion is caused by an electrochemical reaction in the soil environment

called a “galvanic cell” or sometimes a “corrosion cell.” The galvanic cell is made up of three parts: the

anode, the cathode, and the electrolyte.

The environment that we are talking about (soil, in this example) is called the electrolyte. The electrolyte

is defined as an ionic conductor. In other words, it transfers or allows the transfer of ions.

The electrode at which chemical reduction occurs is called the cathode (positive current enters the

cathode from the electrolyte). The electrode at which chemical oxidation (corrosion) occurs is called the

anode (positive current leaves the anode and enters the electrolyte).

It is necessary for the anode and the cathode to be connected together electrically to complete the

corrosion cell. For a corrosion cell to function, there has to be an electrical potential between the anode

and the cathode.

This electrical potential can result from a number of conditions. Two of the most common corrosion cells

encountered result from:

1. Dissimilar metals in the same environment

2. The same metal in dissimilar environments

11.1.2 Dissimilar Metals

When two dissimilar metals are placed in the same environment, there will be a difference in dc voltage
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because of the different activity levels that the metals occupy in the Electromotive Force (EMF) Series.

In a typical substation, a voltage difference on the order of 1 volt will probably exist between a copper

ground cable and galvanized steel structures, and a dc corrosion current will flow from the steel. The

current will be limited by the resistance between the structures in accordance with Ohm’s law and also by

surface films, which may greatly reduce the current and the rate of corrosion. Another example of

dissimilar metal corrosion would be an underground bare copper cable and a galvanized conduit buried in

the ground inside a substation.

There are other examples of dissimilar metal corrosion.

11.1.2.1 Old Steel vs. New Steel: When old steel is connected to new steel, the old steel actually acts

as the cathode and the new steel acts as the anode. See Figure 11-1.

Figure 11-1: Dissimilar Metal Corrosion—Old Steel vs. New Steel

11.1.2.2 Stress Corrosion: Areas of metal that are under stress (i.e., straight pipe that is bent for

construction purposes) tend to be anodic compared to areas that are not under stress.

11.1.3 Dissimilar Environments

Differences in dc potential along the ground grid conductors or concentric neutrals can be caused by

varying oxygen concentrations, different values of pH, or because the soil resistivity varies over a fairly

wide range. In this case, areas effected by corrosion may be at random locations that would have to be

located.

There are other examples of dissimilar environment corrosion.

11.1.3.1 Oxygen vs. No Oxygen: One element that is very important in its effect on underground

corrosion is oxygen. Either through its presence or its absence, oxygen is one of the primary causes of

metal deterioration underground. As a result of soil compaction during backfill, the type of soil, or the

steel conduit being laid in the bottom of the trench, steel conduits often have less oxygen near the bottom

of the pipe. See Figure 11-2.

11.1.3.2 Different Types of Soil from Location to Location: Depending on the type of soil (sandy,

clay, loam, etc.), the pipe may vary from anodic to cathodic. This generally does not occur in smaller

substations, but should be a consideration in larger substations. See Figure 11-3.
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Figure 11-2: Dissimilar Environment Corrosion—More Oxygen vs. Less Oxygen

Figure 11-3: Dissimilar Environment Corrosion—Different Soil Types

For a more detailed treatment of basic corrosion theory, see the References in Section 11.4.

11.2 PRELIMINARY PREVENTIVE MEASURES

11.2.1 Surveys

It is important that certain preliminary data be obtained prior to final site selection so that corrosion
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problems can be avoided or minimized. This procedure ensures that design and/or material selection will

minimize possible corrosion problems. The preliminary data should include the following items.

11.2.1.1 Soil Resistivity Survey: A soil resistivity survey at each proposed site is the necessary first

step, since the economic choices of materials and designs will vary with soil resistivity. Once soil

resistivities are known, decisions can be made regarding overhead or underground feeder construction,

the use of jacketed cable, and anodes or other cathodic protection against corrosion.

For soils of high resistivity (over 200 ohm-meter) where both grounding and cathodic protection are

difficult to accomplish, semiconducting jacketed cable may be the most effective.

One way to obtain this information would be using the four-pin method. See Section 9.3 of this bulletin

for further information on soil resistivity.

11.2.1.2 pH Survey: A pH survey of each substation site should also be a part of any corrosion

evaluation. Soils seldom have a pH lower than 5 (acid) or greater than 8 (alkaline), where 7.0 is neutral.

Soils with a pH of 5 and lower can contribute to severe corrosion and rapid deterioration of exposed

metals. Acid soil conditions are usually limited to soils containing decomposed acidic plants and needles

from coniferous trees. Soils with a pH of 8 and above can contain a high concentration of dissolved salts

resulting in a low soil resistivity. Soils of this type are referred to as alkaline or calcareous. Alkaline

soils are high in sodium and potassium, while calcareous soils are high in magnesium and calcium.

Alkaline earth elements such as magnesium and calcium tend to form protective layers on ferrous metal

surfaces and are considered favorable environments for metals.

11.2.2 Selection of Materials

Select materials to minimize dissimilar-metal corrosion effects due to buried copper and steel (or other

metals) in the same environment. For example, the grounding system at any one substation location

should consist wholly either of copper or steel. This is particularly important in corrosive soils such as

those with low values of earth resistivity (less than 20 to 30 ohm-meter). No commonly used material can

be wholly immune to possible corrosion damage. However, in the absence of a planned maintenance

program to periodically determine the specific condition of ground grid conductors, the final choice of

material should consider the available, proven historical records of the materials under consideration.

Where buried steel such as steel anchor assemblies, piping, and conduit is of necessity connected to the

copper grounding grid for safety, the higher the ratio of steel-to-copper surface area, the less likely will be

the adverse effects of corrosion of the steel. Where the copper grounding system is the only metal placed

in the substation soil, be alert for possible interconnected steel in nearby line anchor assemblies, piping,

wells, conduit, or oil or gas lines that may be inadvertently connected to the grounding system and subject

to accelerated corrosion. If such conditions exist, cathodic protection of the interconnected steel may be

necessary. For large substations, a rectifier-type cathodic protection scheme may be required.
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11.3 TESTING AND INSTALLATION

11.3.1 Earth Resistivity Measurements

Earth resistivity in undisturbed soil may be determined typically with a four-terminal ground tester and

test electrodes. Avoid test locations close to parts of an existing ground mat or other buried metal. See

Section 9.3 of this bulletin for a full description of testing and analyzing resistivity.

11.3.2 Soil Samples

Obtain soil samples at the approximate depth of the underground structures in the substation. These

samples can usually be obtained with a soil auger. A pH reading can be taken immediately, or the soil

can be stored in an airtight container such as a plastic bag and the readings taken at a later time. Lower

pH values generally indicate more corrosive soils. These tests can be handled by a testing laboratory or

done in house using commercially available soil testing kits.

11.3.3 Anode Locations

Sacrificial anodes, where used, should be placed:

1. At locations of the lowest resistivity soil within or near the substation area

2. At depths at least equal to those of the ground grid and/or other assemblies to be protected

3. Three to six meters away from the buried bare conductors or other assemblies, to the extent

that space allows

Usual anode locations are at edges or corners of the ground grid, and at structures in low-resistivity

locations near the substation. The connection from anode to the system neutral and station grid should be

reliable and have low resistance. Compression fittings or exothermic welded connections are preferable

to bolted connections or clamps.

11.3.4 Underground Connections

Exothermic welding is preferred to clamps or bolted connections for dissimilar-metal (copper-to-steel)

connections underground. For similar metal, copper-to-copper or steel-to-steel (galvanized) connections,

suitable bolted or clamped connections with clamps of the same material should be satisfactory. Cover

welds with mastic or other underground coating (such as used for pipelines) in very corrosive soils with

resistivities in the range below 10 ohm-m. In most soils this is not considered necessary.

11.3.5 Estimating Corrosion Conditions from DC Potential Measurements

One frequently used indicator of corrosion or freedom from corrosion is the dc potential (voltage)

measured from a copper–copper sulfate reference electrode or half-cell. This measurement is made as

shown in Figure 11-4.

The copper–copper sulfate half-cell is a copper rod surrounded by a saturated solution of copper sulfate

(blue vitriol) in water, with a porous plug to allow the solution to come in contact with the soil. The

voltmeter usually is a potentiometer (null-type) voltmeter or a special high-resistance (10 megohms or
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Figure 11-4: DC Potential Measurement for Indication of Corrosion Conditions

higher) low-range voltmeter. However, a useful reading may also be possible with a 20,000 ohm-per-volt

dc meter with a 2.5-volt range. See Figure 11-5.

The variations in dc potential are small and often expressed in millivolts. Usually, the neutral is negative

with respect to the copper–copper sulfate half-cell. Table 11-1 lists some typical potentials for metals and

combinations of metals that may be present and connected to a substation ground grid.

Table 11-1: DC Potentials of Various Buried Metals.

Based on Hagan, “Basic Electrical and Corrosion

Fundamentals Involved in Pipeline Corrosion.”

Buried Metal Typical Potential Volts

Zinc or new galvanized steel –1.1 or more negative

Steel fully protected against corrosion –0.85 or more negative

Old buried steel pipe –0.65

“Copper-grounded” neutral with

anchors and steel piping connected

–0.50 to –0.65

All-copper grounded neutral –0.30

DC potential measurements indicate the effectiveness of anodes for cathodic protection. For example,

anodes may be installed at a copper-grounded substation to relieve corrosion of anchor rods near the

substation. If the anodes are effective, the station ground grid becomes more negative. The potential

might be shifted from –0.55 volt to –0.75 volt. In a situation where original anchor rods have begun to

fail after 15 years, such a change in potential should be adequate to ensure permanence of the newly

installed anchors. In very corrosive soils (such that anchor rods might otherwise fail in five years or less),

a shift to at least –0.85 volt may be needed for complete protection.
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Figure 11-5: Copper–Copper Sulfate Half-Cell

Very little is known about potentials of copper corroding in soil. However, copper corrosion has been

observed in a neutral to moderately alkaline soil (pH 7.1 to 8.0) at potentials of –0.10 to +0.047 volt with

reference to a copper–copper sulfate half-cell. For the present, if cathodic protection of copper is found to

be necessary, a potential of –0.35 volt is suggested for purposes of design.

In distribution substations, underground exit feeders with bare concentric neutrals may be vulnerable to

corrosion. They should be provided with cathodic protection if the possibility of corrosion is believed to

exist.

In addition to dc potentials, the measurements in Table 11-2 have significance in underground corrosion

surveys.

Earth resistivity measurements help to indicate the degree of corrosiveness of the soil. Low resistivity

soils (lower than 15 to 20 ohm-m) are regarded as relatively corrosive to steel or copper. High resistivity,
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well-aerated soils such as sand and gravel may also be corrosive to copper. Locations of sudden change

in earth resistivity, including roadside ditches where salt accumulates, are probable locations of corrosion.

Table 11-2: Soil Corrosiveness vs. Resistivity

Severely Corrosive 0-5 ohm-m

Very Corrosive 5-10 ohm-m

Corrosive 10-30 ohm-m

Moderately Corrosive 30-100 ohm-m

Slightly Corrosive 100-250 ohm-m

Less Corrosive Above 250 ohm-m

Guy current measurements, at cable terminal poles and other guyed poles nearby, indicate locations of

anchor rod corrosion and probable corrosion of other buried steel in the vicinity. See Figure 11-6.

Figure 11-6: Voltage Drop Measurement to Determine Direct Current Flow

Neutral-to-earth resistance measurements indicate the overall effectiveness of grounding. Multi-grounded

electric distribution neutrals normally have a low resistance to earth. See Figure 11-7.

11.4 REFERENCES

Corrosion Resistance of Metals and Alloys, 2d ed., New York: Reinhold Publishing Corporation, 1963.

Dedman, J.C., “Corrosion Surveys – Electrical Measurement Techniques,” Presented at 33rd Annual

Appalachian Underground Corrosion Short Course, 1988.

Hagan, M.T., “Basic Electric and Corrosion Fundamentals Involved in Pipeline Corrosion,” Presented at

33rd Annual Appalachian Underground Corrosion Short Course, 1988.
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National Association of Corrosion Engineers, NACE Basic Corrosion Course, Chapters 1, 2, 5, and 6,

1971.

NACE Std. RP-01-74, “Recommended Practice - Corrosion Control of Electric Underground Residential

Distribution Systems.”

Peabody, A.W., “Control of Pipeline Corrosion,” National Association of Corrosion Engineers.

Uhlig, H.H., “Corrosion and Corrosion Control,” 2d ed., New York: John Wiley and Sons, Inc., 1968.

Figure 11-7: Neutral-to-Earth Resistance Measurements
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CHAPTER 12

PROTECTIVE RELAYING

12.1 GENERAL

12.1.1 Purpose of Protective Relays

Protective relays are used to detect defective lines or apparatus and to initiate the operation of circuitinterrupting devices to isolate the defective equipment. Relays are also used to detect abnormal or

undesirable operating conditions other than those caused by defective equipment and either operate an

alarm or initiate operation of circuit-interrupting devices. Protective relays protect the electrical system

by causing the defective apparatus or lines to be disconnected to minimize damage and maintain service

continuity to the rest of the system.

12.1.2 Design Objectives

The design objectives of a protective relaying are to minimize the effects of a system disturbance and to

minimize the possible damage to power system equipment. A good protective relaying system will

address dependability, security, speed, and simplicity.

12.1.2.1 Dependability: Dependability is the certainty of correct operation in response to system

troubles. Dependability includes the reliable operation of the relay system operating when it is supposed

to and selectivity of the relay system operating to isolate the minimum amount of the system necessary to

provide continuity of service.

12.1.2.2 Security: Security is the ability to avoid misoperations between faults. Every relay system

has to be designed to either operate or not operate selectively with other systems.

12.1.2.3 Speed: Speed means clearing all faults in the shortest possible time with all due regard to

dependability and security.

12.1.2.4 Simplicity: A relaying system should be no more complex than is required for any given

application. Adding more equipment into a scheme than is necessary for good coverage adds to the

possibility of equipment failure and misoperation.

12.1.3 Indications of Defective Equipment or Abnormal Conditions

12.1.3.1 Short Circuits: A short circuit is an abnormal connection of relatively low resistance

between two or more points of differing potential in a circuit. If one of these points is at ground potential,

it is referred to as a “ground fault.” If ground potential is not involved, it is referred to as a “phase fault.”

Phase faults cause excessive currents and low voltages. Ground faults may or may not cause excessive

currents or abnormal voltages, depending on whether the system is normally ungrounded, high- or lowresistance grounded, or effectively grounded.

12.1.3.2 Excessive Heating: Equipment is designed to deliver full-rated capacity with the

temperature maintained below a value that will not be damaging to the equipment. If operating

temperature becomes excessive, the life of the equipment (generator, motor, transformer, etc.,) will be
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reduced. Excessive heating may be caused by overloading, high ambient temperatures, improper cooling,

or failure of cooling equipment.

12.1.3.3 Overvoltage: Equipment is designed for normal operating voltages as stated on its

nameplate with a slight allowance (usually about 5 percent) for normal overvoltage. Abnormal

overvoltage may cause:

1. Insulation failure

2. Shortening of the equipment life

3. Excessive heating as a result of greatly increased excitation currents where electromagnetic

devices are used

4. Excessive heating in resistors used in controls

5. Failure of transistors and other electronic devices

12.1.3.4 Undervoltage: Continued undervoltage will likely cause overheating of motors and

dropping out of contactors, and lead to the failure of electrical equipment.

12.1.3.5 Unbalanced Phase Conditions: On balanced three-phase systems with balanced three-phase

loads, a sudden unbalance in the current or the voltages usually indicates an open or a partially shorted

phase. An unbalanced voltage condition is especially serious for three-phase motors because negative

sequence currents can lead to considerable overheating within the motor. On balanced three-phase

systems with single-phase loads, the loading on each phase may normally vary, depending on the

magnitude of each single-phase load. However, it is desirable to keep this unbalance to a minimum to

maintain balanced voltages for three-phase loads. Unbalanced conditions, which include single-phase and

double-phase faults with or without ground, can be detected with the use of negative and zero sequence

relay elements.

12.1.3.6 Reversed Phase Rotation: Reversed phase rotation can occur after circuit changes have

been made or during an open phase condition. Reversed rotation of motors may cause considerable

damage to the facility driven by the motors, such as a conveyor.

12.1.3.7 Abnormal Frequency: Abnormal frequencies can occur when the load does not equal the

generation. The frequency may be above or below the system normal frequency. Many facilities such as

electric clocks, synchronous motors, etc., are frequency sensitive.

12.1.3.8 Overspeed: Considerable mechanical damage can be done to generators and motors because

of overspeed. Excessive overspeed may cause parts of the generator or motor to be thrown for

considerable distances, which is dangerous to personnel as well as to other facilities. Generators or seriesconnected motors may reach dangerous overspeeds when loads are suddenly removed.

12.1.3.9 Abnormal Pressure: In electrical equipment, such as transformers, that use liquid as an

insulating fluid, high internal pressures can be created during internal faults.

12.1.3.10 Abnormal Impedance: Electrical equipment has impedance associated with it that either

has definite known values or values that may vary within a known range during known varying operating

conditions. These values are normally determined during the manufacture and installation of equipment.

Substantial deviations in the impedance of the equipment can indicate a failure of the equipment.
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12.1.3.11 Out-of-Step Conditions: Electric power systems in North America operate at a frequency

of 60 hertz . All the generators and rotating equipment on the system rotate at an rpm to maintain the

60 hertz frequency. As such, each machine on the electrical system maintains a relative position, or phase

angle, with respect to every other machine on the system. Once a machine exceeds a critical phase angle,

it can no longer stay in phase with the system. It is said to have moved out of step with the system, and

has to be removed from the system and resynchronized to the system in order to establish operation. Outof-step conditions are typically monitored through the use of impedance relays and set to trip or block the

trip of breakers in order to segment the system at predetermined locations based on system stability

studies.

12.1.3.12 Excessive System Phase Angles (Synchronism Check): The closing of a circuit breaker

on a system connects the electrical systems on either side of the circuit breaker. The closing of the

breaker will cause any difference of voltage and phase angle across the breaker to be reduced to zero,

causing current flow from one system to the other to equalize the system voltages, currents, and phase

angles. If the voltage and phase angle differences across the breaker are too much, excessive currents can

flow, resulting in a disturbance to the system, possibly damaging the breaker or adjacent rotating

equipment. Typically, the voltage and phase angle across the breaker are compared to confirm the

systems are within proper limits before the breaker is closed.

12.2 FUNDAMENTAL CONSIDERATIONS

12.2.1 Phasors

A phasor is a complex number used to represent electrical quantities. In protective relaying systems,

phasors are used to aid in applying and connecting relays and for analysis of relay operations after faults.

Phasor diagrams have to be accompanied by a circuit diagram. The phasor diagram shows the magnitude

and relative phase angle of the currents and voltages, while the circuit diagram shows the location,

direction, and polarity of the currents and voltages.

12.2.2 Polarity

The relative polarities of a current transformer’s primary and secondary terminals are identified either by

painted polarity marks or by the symbols “H1” and “H2” for the primary terminals and “X1” and “X2”

for the secondary terminals. The convention is that, when primary current enters the H1 terminal,

secondary current leaves the X1 terminals. Or, when current enters the H2 terminal, it leaves the X2

terminal. When paint is used, the terminals corresponding to H1 and X1 are identified. Since ac current

is continually reversing its direction, one might well ask what the significance of polarity marking is. Its

significance is in showing the direction of current flow relative to another current or to a voltage, as well

as to aid in making proper connections. The polarity marks for a potential transformer have the same

significance as for a current transformer.

12.2.3 Faults

A system fault (short circuit) is a condition in which the electric current follows an abnormal path as a

result of the failure or removal of the insulation that normally confines the electric current to the

conductors. Insulation is usually either air or high-resistive material that may also be used as a

mechanical support. Air insulation can be accidentally short-circuited by birds, rodents, snakes, kite

strings, tree limbs, etc.; broken down by overvoltage due to lightning; or weakened by ionization due to a

fire or smoke. Organic insulation can deteriorate because of heat or aging or can be broken down by
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overvoltage due to lightning, switching surges, or faults at other locations. Porcelain insulators can be

bridged by moisture with dirt or salt, or can develop a crack as a result of mechanical forces.

12.2.4 Symmetrical Components

Symmetrical components are the foundation for obtaining and understanding fault data on three-phase

power systems. Formulated by Dr. C.L. Fortescue in a classic AIEE paper in 1918, the symmetrical

components method was given its first application to system fault analysis by C.F. Wagner and R.D.

Evans in the late 1920s and early 1930s. W.A. Lewis added valuable simplification in 1933. Today, fault

studies are commonly made with a digital computer. System changes can be accurately modeled and

incorporated into the database. Knowledge of symmetrical components is important both in making a

study and in understanding the data obtained from the computer. It is also extremely valuable in

analyzing faults and relay operations. A number of protective relays are based on symmetrical

components. Symmetrical components are one of the most powerful technical tools used by a relay

engineer. The practical value lies in the ability to think and visualize in symmetrical components.

Several good courses on symmetrical components are available from manufacturers. The relay engineer

should become well acquainted with the use of symmetrical components since it is a primary means of

communicating about and analyzing system faults.

12.2.5 Relay Input Sources

Instrument transformers provide relays with currents and voltages that are proportional to voltage and

currents flowing in the primary circuit. Voltage signals are obtained from potential transformers (PTs)

and current signals from current transformers (CTs). Instrument transformers and their applications are

described in Section 5.10.

12.3 BASIC RELAY TYPES

12.3.1 General

Protective relays consist of three basic modules:

1. An input module

2. A decision module

3. An output module

See Figure 12-1. The modules are each constructed of components that will vary depending on the type

of construction of the relay: electromechanical, static, or microprocessor.

Figure 12-1: Logical Representation of Protective Relays

Relays are also classified according to the function they provide to the system. The five most common

functions are:
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1. Protection

2. Regulation

3. Reclosing and synchronization

4. Monitoring

5. Auxiliary

The primary emphasis of this discussion is protection. Other functions are included as applicable.

Each of the basic relay modules operates to perform tasks as follows.

12.3.1.1 Input Module: The principal input module task is to receive the inputs from the electrical

system to the relay, generally in the form of currents, voltages, and status input contacts. It acts as the

interface between the relay decision module and the electric power system, protecting the sensitive

decision module from the harsh environment of the electric power system. The electrical system input

section typically consists of transformers, transactors, zener diodes, electronics, and other equipment to

provide a signal, proportional to the inputs, to the decision module. The input equipment will condition

the input signals to be in a format required by the decision module. Conditioning may include converting

the voltage, contact, or current inputs into voltages or currents suitable to electronic equipment.

Conditioning may also include the conversion of the signals from analog values to digital values. The

input section also will typically contain equipment that will provide protection for the relay to withstand

the surges, transients, and oscillations that may be present in the substation environment.

An additional task of the input section of the relay is to provide for the input and storage of the relay

settings. For electromechanical and static relays, this is most often the setting of various taps, dials

(which will normally preset tension on a spring), and selector switches on the face of the relay. For

microprocessor relays, the input section often includes a series of push buttons that will allow the input of

relay settings or the input of requests for the relay to display settings or data processed by the relay. The

relay settings will be stored for use by the relay in providing its protective functions.

Microprocessor relays often include a number of additional inputs to the relay. Included in these inputs

are the power supply; clock signals to provide sequence of events (SOE) timing; communication ports to

provide direct computer, SCADA, or other data inputs; and front panel push buttons to set the relay or

scroll through the metering functions. Microprocessor relays are often provided with multiple relay

setting groups that will allow for changes in the electric power system configuration. The change from

one settings group to another can usually be keyed locally by an external contact in the substation control

scheme or remotely via SCADA. It should be noted that there is an inherent danger of inadvertently

changing a relay setting or setting group with this type of microprocessor relay.

The relay engineer has to be aware of the electrical system inputs that are available for use in determining

the failure of the electric power system or electric power system components. Knowledge of the electric

power system and how the system responds to various failures is invaluable in making decisions as to the

types of relays that are used to protect the electric power system.

12.3.1.2 Decision Module: This module monitors the input data included in the relay settings input to

the relay and the system data, including currents, voltages, status contacts, and control signals that were

input to the relay. The module will evaluate the system data in comparison to the relay settings. When

the system data exceed the threshold determined by the relay settings, this module will signal the output

module to function and record the results. The quantities to which the relay responds usually designate

the relay type.
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For electromechanical relays, the decision module often consists of disks that work by induction,

plungers, or solenoids; levers that will work on a balance beam principle; units that work on the basis of

thermal characteristics; or D’Arsonval units that consist of a combination of fixed magnetic and

electromagnetic elements. Each of the units is configured with a contact that either makes (closes) or

breaks (opens) upon the operation of the device. The recording of the action is usually accomplished by

the dropping of a target to indicate the relay operation. The module compares the input relay settings to

the input signals through the inherent magnetic or thermal action of the relay to overcome the spring

tensions and inertia associated with the relay settings. Relays may operate (1) instantaneously, (2) with

some definite time delay, or (3) with a time delay that varies with the magnitude of the quantities to which

the detecting element responds.

Static relays replace the electromechanical components with solid-state components and make the

comparisons by electronic means. Static or solid-state detecting elements generally convert the current,

voltage, or power inputs to proportional dc millivolt signals that are then applied to adjustable transistor

amplifiers. These amplifiers have a “go–no go” characteristic that causes an input signal up to the set

level to produce no output and input signals beyond that level to produce full output. The output may be

another dc millivolt signal applied to further transistor logic or to a contact closure. Indication of the

operation of the relay is usually accomplished by the dropping of a target to indicate the relay operation.

Microprocessor relays replace the decision module with a small digital computing unit that utilizes

sampled input data and digitized setting parameters. Comparisons are made digitally by the computer

performing a calculation or series of calculations, comparing the relay setting information to the periodic

samples obtained from the electric power system. When the threshold values are exceeded, the module

activates the output module. Most relays will also store a number of metering values, the status of input

devices, intermediate logic elements, and other information available to the relay in output storage

registers. The information is then available for retrieval by the engineer at his convenience, either locally

at the substation or remotely through communications that are often provided to the relay.

Microprocessor relays usually include internal self-checking functions for the majority of their functions.

Should a failure occur within the logic of the relay, an alarm will be given to the relay output module that

the relay is in an alarm condition. The relay engineer also needs to be aware of the functions and features

that may not be covered by an alarm, such as the capability of the output relays to function.

12.3.1.3 Output Module: This module provides an output from the decision module to the control

system in order to operate electric power system equipment and isolate faulty system components.

For electromechanical relays, this system typically consists of output contacts or auxiliary relays with

multiple contacts. The contacts act as the interface between the relay and the electric power control

system. These contacts are then used to trip circuit breakers, provide alarms, trip other relays such as

lockout relays and send signals via communications to remote equipment or personnel, or other functions.

The contacts will carry specific ratings for the voltages and currents they will successfully carry or break.

Static relays provide the option for outputs to be either auxiliary reed (magnetically activated) relays and

their associated contacts or solid-state-controlled thyristors. Electronically controlled thyristors are

usually faster than their relay counterparts. Triggering circuitry may include opto-isolators to provide

isolation between the relay and the harsh environment of the electric control system.

Microprocessor relays will use either reed relays or solid-state-controlled thyristors for output elements.

Usage will vary between manufacturers and may be optional to the user. In addition to the standard relay

outputs, microprocessor relays may include a number of additional output contacts that may be
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programmed for the user’s requirements. One of the output contacts is normally designated as the relay

alarm contact. Most relays include a number of output storage registers where the relay stores a number

of metering values, the status of input devices, intermediate logic elements, and other information

available to the relay. The information is then available for retrieval by the engineer at his convenience,

either locally at the substation or remotely through communications that are often provided to the relay.

Most microprocessor relays include communication capabilities that allow the relay to transmit data in

digital format to computers, SCADA systems, or local control systems.

Many microprocessor relays also include a display unit as a part of the output module. This display unit

is typically used to display metering values of the inputs that are brought to the relay or metering

information that is calculated in the relay. The display may also show other functions of the relay, such

as the display of internal variables, flags, and input parameters. The display typically provides a means of

getting information out of the relay without the requirement to connect a computer to one of the output

ports.

12.3.2 Relay Selection

The type of relay selected by the relay engineer for an application is of primary importance. The engineer

has to determine, with existing system knowledge or with additional studies, the types of failure that each

component of the electric power system can experience and the characteristics of the failure. The

electrical system inputs that will be available to the relay and the speed with which the relay has to

operate to maintain electrical system stability has to be known. With this information, the engineer can

apply relays that will measure the identified characteristics of the electric power system component with

the previously established relay settings and operate dependably and securely in protecting the electrical

system. The relay engineer should consider some of the following factors.

12.3.2.1 Electromechanical relays are the oldest and have the most history associated with them. They

provide discrete protection functions within each case. Relay settings are usually straightforward and

well documented in most instruction books. The relay engineer has to have a relatively good idea of the

magnitudes of electrical signals that will be applied to the relay in order to obtain the proper range of

settings for each application.

12.3.2.2 Static relays generally provide discrete functions similar to electromechanical relays. Since

the operation of the relays depends only on threshold values being met, these relays are generally faster

than their electromechanical counterparts. Static relays often come in cases similar to their electromechanical counterparts, making replacement relatively simple. Static relays are also available in

“packages” that include all the protective functions for the line in a single rack.

12.3.2.3 Microprocessor relays often can accommodate more complex system operation because of

the inputs provided to the relay and the programming features included with the relay. In many cases,

numerous functions are provided in the relay so that the number of discrete relays required for protection

may be reduced substantially. In many cases, additional functions may be provided to protect a system

from abnormal conditions that might not otherwise be considered based on the low occurrence of such

conditions or because of other considerations.

12.3.2.4 Microprocessor relays often provide the relay engineer with many more options for providing

protection than either their electromechanical or static relay counterparts. Once the inputs to the relay are

obtained, the decision module can then be programmed to provide many protective functions with these

inputs. This information can also be used to implement the transmittal of data remotely through SCADA
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or other data retrieval means. In terms of the number of functions, the microprocessor relay will often

provide more protective functions for the dollar spent.

This type of relay may be slightly slower to operate than some of the electromechanical or static relays

that are available. The operating speeds of microprocessor relays are typically in the range of 1.5 to

2 cycles. Some static relays may operate in less than 1 cycle.

Microprocessor relays usually include internal self-checking functions for the majority of their functions.

As noted, the relay engineer also needs to be aware of the functions and features that may not be covered

by an alarm, such as the capability of the output relays to function.

12.3.2.5 In new installations, the use of microprocessor relays may result in reduced cost since fewer

relays are required. Generally, less floor space is needed so smaller control buildings are needed for the

equipment. This may result in reduced auxiliary power system requirements. The interconnection wiring

in a panel is also reduced since many of the protective functions are included in one relay enclosure.

12.3.2.6 For simple systems, control system design may be equally simple with electromechanical,

static, and microprocessor relays. If the complexity of the power system requires many specific functions

of protection, the microprocessor relays may provide a simpler installation.

12.3.2.7 Consider the effects of the protective relay system on the personnel who will operate and

maintain the equipment. If new devices are being proposed, special training may be required for them to

operate and maintain the equipment. Additional equipment may be necessary for relay testing, such as

computers to connect locally to the microprocessor relays.

12.3.2.8 Consider the lifetime of the installation the relays are being applied in. Will spare parts be

available for the devices? Will the manufacturer have personnel available to answer questions on the

relays in the future?

12.3.2.9 Be aware that the complexity of the relay will increase the complexity of the relay settings.

A simple electromechanical overcurrent relay has basically two settings: a tap setting for the pickup of the

relay and the time dial to determine the time delay until trip, if any. A feeder with four overcurrent relays

will thus have eight settings, with a set of common phase settings and ground settings. By comparison, a

microprocessor relay may have up to 10 or more pages of relay settings. A small part of these settings

will actually involve the protective functions of the relay; however, the relay engineer will need to study

the applicability of the functions and determine whether or not to use them. In general, if the relay

engineer does not need the function, the function should be disabled in the relay to avoid overcomplicating the protection scheme.

12.3.2.10 Do not ignore the personal preferences of the cooperative regarding the protective schemes

and equipment used. Design and application of protective relaying schemes is an art that uses science to

make it work. In most cases, many relays and protective schemes can be used to protect a line or piece of

equipment. What is used depends largely on the skill of the relay engineer and preferences of the people

who will be operating and maintaining it.

12.3.2.11 Substation automation combines many functions, such as relaying, metering, and data

acquisition. The relay engineer should be aware of the benefits and traps included in implementing relays

in a substation automation project.
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Substation automation, discussed further in Chapter 14, provides many more options for controlling

equipment. There are some cases where firms use programmable logic controllers to perform protective

relay functions. These cases are usually either very simple, such as providing a timing function, or very

complex, providing logic to control switching or testing of a three-terminal line. In the majority of cases,

the relay engineer should use relays to provide the relay functions and not introduce automation

equipment into the relay functions. It is recommended the relays be used to do what they are designed to

do, provide system functions, and use automation equipment to provide additional operating features or

metering functions.

12.3.2.12 To communicate relaying functions being used on a system, device function numbers and

contact designations have been developed to identify devices in protective relay schemes. Appendices F

and G to this chapter list the function numbers and contact designations summarized from IEEE

Std. C37.2, “IEEE Standard Electrical Power System Device Function Numbers and Contact

Designations.”

12.3.3 Overcurrent Relay

The overcurrent relay responds to a magnitude of current above a specified value. There are four basic

types of construction: plunger, rotating disc, static, and microprocessor. In the plunger type, a plunger is

moved by magnetic attraction when the current exceeds a specified value. In the rotating induction-disc

type, which is a motor, the disc rotates by electromagnetic induction when the current exceeds a specified

value. Static types convert the current to a proportional dc millivolt signal and apply it to a level detector

with voltage or contact output. Such relays can be designed to have various current-versus-time operating

characteristics. In a special type of rotating induction-disc relay, called the voltage restrained overcurrent

relay, the magnitude of voltage restrains the operation of the disc until the magnitude of the voltage drops

below a threshold value. Static overcurrent relays are equipped with multiple curve characteristics and

can duplicate almost any shape of electromechanical relay curve. Microprocessor relays convert the

current to a digital signal. The digital signal can then be compared to the setting values input into the

relay. With the microprocessor relay, various curves or multiple time-delay settings can be input to set

the relay operation. Some relays allow the user to define the curve with points or calculations to

determine the output characteristics.

The protective characteristic of the overcurrent relay, in terms of the impedance diagram, is a circle,

assuming a constant voltage, with the relay located at the origin of the R-X coordinate diagram (see

Figure 12-2). The relay operates on the simple magnitude of current passing through it according to the

settings applied to the relay.

The overcurrent relay may be the simplest relay in concept to use. When the current exceeds the setting

value, it causes a trip. Complications in applying the relay may occur when the system does not provide

adequate differentiation between current values, such as between short lines on a system with high fault

current duties. When a number of overcurrent relays are used sequentially in a circuit, the trip delay times

may become excessive.

12.3.4 Distance Relay

The distance relay responds to a combination of both voltage and current. The voltage restrains

operation, and the fault current causes operation that has the overall effect of measuring impedance. The

relay operates instantaneously (within a few cycles) on a 60-cycle basis for values of impedance below

the set value. When time delay is required, the relay energizes a separate time-delay relay or function

with the contacts or output of this time-delay relay or function performing the desired output functions.
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Figure 12-2: Overcurrent Protective Characteristic

The protective characteristic of the distance relay, in terms of the impedance diagram, is a circle with the

relay located at the origin of the R-X coordinate diagram (see Figure 12-3). The relay operates on the

magnitude of impedance measured by the combination of restraint voltage and the operating current

passing through it according to the settings applied to the relay. When the impedance is such that the

impedance point is within the impedance characteristic circle, the relay will trip. The relay is inherently

directional. The line impedance typically corresponds to the diameter of the circle with the reach of the

relay being the diameter of the circle.

Figure 12-3: Distance Protective Characteristic

Since the relay responds directly to the value of impedance represented by the fault current and voltage

applied to the relay, it will discriminate more correctly between the location of faults since the electric

power system also may be represented by its impedance. The distance relay may be used more

successfully on an electric power system when the magnitudes of fault current do not provide adequate

location differentiation to be able to accurately trip specific breakers and isolate a fault.
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The distance element in a relay may be used when a component of the electric power system, such as a

transmission line, has defined impedance characteristics. Several distance elements are often used, with

the circles passing through the origin of the R-X diagram, to provide several zones of protection for the

system component. Additional zones of protection will be used with timers to provide direct protection,

or without timers and used in pilot protection schemes requiring communications from all remote

terminals of the transmission line. Distance elements may be used for out-of-step protection with the first

zone impedance characteristic passing through the R-X impedance coordinate diagram origin and the

remaining zones concentric around the first zone.

12.3.5 Differential Relay

The differential relay is a current-operated relay that responds to the difference between two or more

currents above a set value. The relay works on the basis of the differential principle that what goes into

the device has to come out (see Figure 12-4). If the current does not add to zero, the “error” (fault)

current flows to cause the relay to operate and trip the protected device.

Note: For simplicity of illustration, the CTs are indicated with a 1:1 ratio

and equal currents in the primary and secondary of the CTs.

Figure 12-4: Differential Relay Principle

The differential relay is used to provide internal fault protection to equipment such as transformers,

generators, and buses. Relays are designed to permit differences in the input currents as a result of
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current transformer mismatch and applications where the input currents come from different system

voltages, such as transformers. A current differential relay provides restraint coils on the incoming

current circuits. The restraint coils in combination with the operating coil provide an operation curve,

above which the relay will operate. Some of the relays for specific equipment, such as transformers, use

additional restraint proportional to the harmonics sensed in the incoming currents. Setting levels are

based on the characteristics of the protected equipment.

Differential relays are often used with a lockout relay to trip all power sources to the device and prevent

the device from being automatically or remotely re-energized. The relays are very sensitive. The

operation of the device usually means major problems with the protected equipment and the likely failure

in re-energizing the equipment.

12.3.6 Overvoltage Relay

The overvoltage relay responds to a magnitude of voltage above a specified value. As noted, the basic

types of construction include plunger, rotating induction-disc, static, and microprocessor relays, all of

which are discussed in Section 12.3.3.

12.3.7 Undervoltage Relay

The undervoltage relay responds to a magnitude of voltage below a specified value and has the same

basic construction as the overvoltage relay.

12.3.8 Power Relay

A power relay responds to the product of the magnitude of voltage, current, and the cosine of the phase

angle between the voltage and current, and is set to operate above a specified value. The basic

construction includes the rotating induction-disc, static, or microprocessor relay. The relay is inherently

directional since the normally open contacts close for power flow in one direction above a set value but

remain open for power flow of any amount in the opposite direction.

12.3.9 Directional Overcurrent Relay

A directional overcurrent relay operates only for excessive current flow in a given direction. Directional

overcurrent relays are available in electromechanical, static, and microprocessor constructions. An

electromechanical overcurrent relay is made directional by adding a directional unit that prevents the

overcurrent relay from operating until the directional unit has operated. The directional unit responds to

the product of the magnitude of current, voltage, and the phase angle between them, or to the product of

two currents and the phase angle between them. The value of this product necessary to provide operation

of the directional unit is small, so that it will not limit the sensitivity of the relay (such as an overcurrent

relay that it controls). In most cases, the directional element is mounted inside the same case as the relay

it controls. For example, an overcurrent relay and a directional element are mounted in the same case,

and the combination is called a directional overcurrent relay. Microprocessor relays often provide a

choice as to the polarizing method that can be used in providing the direction of fault, such as applying

residual current or voltage or negative sequence current or voltage polarizing functions to the relay.

12.3.10 Frequency Relay

A frequency relay responds to frequencies above or below a specified value. The basic types are
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electromechanical relays with a vibrating reed or rotating induction-disc with a frequency-sensitive

circuit, static relays, and microprocessor relays.

12.3.11 Thermal Relay

The thermal relay responds to a temperature above a specified value. There are two basic types: direct

and replica.

12.3.11.1 Direct: In the direct type of thermal relay, a device such as a thermocouple is embedded in

the equipment. This device converts temperature to an electrical quantity such as voltage, current, or

resistance. The electrical quantity then causes a detecting element to operate.

12.3.11.2 Replica: In the replica type of thermal relay, a current proportional to the current supplied

to the equipment flows through an element, such as a bimetallic strip, that has a thermal characteristic

similar to the equipment. When this element is heated by the flow of current, one of the metallic strips

expands more than the other, causing the bimetallic strip to bend and close a set of contacts.

12.3.12 Pressure Relay

The pressure relay responds to sudden changes of either fluid or gas pressure. It consists of a pressuresensitive element and a bypass orifice located between the equipment to which the relay is connected and

a chamber that is part of the relay. During slow pressure changes, the bypass orifice maintains the

pressure in the chamber to the same value as in the equipment. During sudden pressure changes, the

orifice is not capable of maintaining the pressure in the chamber at the same value as in the equipment,

and the pressure-sensitive element mechanically operates a set of contacts.

12.3.13 Auxiliary Relay

Auxiliary relays perform such functions as time delay, counting, and providing additional contacts upon

receiving a signal from the initiating relay. These relays are necessary to provide the broad variety of

schemes required by a power system.

12.4 RELAY SCHEMES

12.4.1 General

Protective relays are most often applied with other protective and auxiliary relays as a system rather than

individually. The following basic scheme descriptions apply to electromechanical, static, and

microprocessor relay systems.

The static and microprocessor relay systems generally have more elaborate logic involved in the tripping

decision, particularly in the area of transient blocking during external fault clearing. Static systems

require more careful treatment of input circuits, i.e., CT and PT leads are often shielded. Static systems

are slightly faster, require less maintenance, and are considerably more costly than the electromechanical

systems.

Microprocessor relays are very versatile and often can perform many functions at a lower cost than other

methods. In addition to basic relaying they may do fault locating, fault data recording, self testing, and

metering. Since microprocessor relays tend to have more protective functions available in a relay case, it
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often allows the relay engineer to provide additional protection the relay engineer would not have

previously considered. Microprocessor relay systems tend to have fewer devices since they contain more

functions in one case. This will tend to reduce the cost of initial installation.

12.4.2 Transmission Line Protection

Transmission lines provide the links between the various points of the power system and deliver power

from the point of generation to the ultimate user. The lines operate at the differing voltages included in

the power system. The significance of a line to the electric power system varies according to the voltage

level, the location of the line in the system, the loads carried by the line, and other factors specific to the

cooperative. Schemes for the relay protection of the line vary according to the significance of the line in

the system, the characteristics of faults on the line, the speed at which a line fault has to be cleared, and

the preferences of the relay engineer and the utility’s practices. The protection schemes available for

transmission line relay protection include:

1. Overcurrent, instantaneous, nondirectional

2. Overcurrent, timed with either inverse curves or discrete times, nondirectional

3. Overcurrent, instantaneous, directional

4. Overcurrent, timed with either inverse curves or discrete times, directional

5. Current differential using overcurrent

6. Distance, instantaneous and timed

7. Pilot with a communication channel between all terminals

Depending on the fault characteristics of the line in question, the relay engineer may use any of the above

relay protection schemes for the protection of phase and ground faults on a transmission line. Protection

schemes may include the use of the schemes individually or in combinations to protect lines with primary

and secondary protection schemes.

The relay engineer has to know the following in determining the relay protection to be used for a

transmission line:

1. The configuration of the transmission line

2. The number of line terminals

3. Whether the line is radial or looped in the system

4. How many taps, if any, are on the line

5. How the line will be loaded

6. Fault levels associated with the line

7. Any other transmission line-specific data peculiar to the system

8. Load-specific information such as specified outage times, temporary power levels, etc.

9. System constraints such as out-of-step relay requirements

10. Coordination requirements with relay systems of the remote line terminals

Higher voltage transmission lines tend to have more sophisticated relay protection systems often using

piloted schemes (the use of communications channels providing information from the remote end of the

line) to provide more security. Transmission lines at 345 kV normally utilize two primary relay schemes

with pilot protection. However, the voltage of the line is not the primary factor in determining the types

of relay protection that may be used. Rather, it is the significance of the line in the power system and the

effect of faults on the line that will determine the speed in which the line has to be removed from the

system when a fault occurs. Some lower voltage systems are in operation where extremely sophisticated
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relay schemes are in place, and some 345 kV systems operate with simplistic schemes because of the

characteristics of the system at the location of the line.

With the above information about the system, the relay engineer can make a decision as to the types of

relay schemes that may be used. The following are schemes used for transmission line protection.

12.4.2.1 Non-Pilot Schemes: Non-piloted schemes involve the use of relays to provide protection

without the use of communications channels providing information from the remote end of the line. The

relay measures the input quantities, makes the action decision based on those quantities, and provides an

output to the circuit breakers or circuit logic at the site of application based on the input and the relay

logic. All the inputs and outputs are local to the site of application.

12.4.2.1.1 Overcurrent Relaying: Overcurrent relay protection is the simplest form of protection

usually applied on lower voltage lines or on radially supplied feeders. It is used occasionally as backup

relay protection for some transmission lines. In its most basic form, nondirectional inverse time

overcurrent relays are applied on radial feeders with two phase devices and one ground device. The fault

current is reduced by increased line impedance the further out on the line the fault occurs, resulting in a

longer time for the relay to trip the feeder.

When a backfeed from another power source is possible on the feeder, directional overcurrent relays may

be used to provide selectivity between faults “in front” of or in the tripping direction of the relay versus

those behind the relay. An instantaneous overcurrent element is often used to protect the transmission line

or feeder for high-current, close-in faults near the terminal where the relay is located.

While this type of protection can be used on a network system with varying contributions from both

directions on the lines, it is extremely difficult to coordinate such a system and it should be avoided where

possible.

12.4.2.1.2 Current Differential with Overcurrent Relay: This circuit uses the differential principle

in connecting the CT circuits and an overcurrent relay instead of a differential relay. The scheme has

limited use since the CTs from all terminals of the line, line segment, or bus has to be connected by the

hardwire circuits back to the overcurrent relay. This connection is more secure and can be set more

sensitively than a simple overcurrent relay application. It also can keep one more overcurrent relay from

being in a string of overcurrent relays that have to be set with increasing time delay.

The circuit is typically used within a substation or generation plant facility where short line segments or

buses require protection that does not need the speed of a differential relay. In applying the circuit, the

relay engineer has to be aware of the CT error and mismatch that may occur in the differential circuit to

the relay and set the relay over any mismatch that may occur.

The circuit is often applied in a variation as an open-differential circuit. This circuit has a number of lines

connected to it with CTs connected in N-1 lines (see Figure 12-5). The overcurrent relay is then set for

the load of the line without the CT. This circuit is often applied as a backup circuit to a transformer

differential circuit at a substation with an in-and-out transmission line. The relay engineer has to be

aware of through faults in the lines with CTs that do not involve the line without the CT. CT mismatch

will result in an error current as a result of the through-fault current that will flow to the relay.

12.4.2.1.3 Step Distance Relaying: Since the distance relay responds to the impedance of the

device it is protecting, it can more easily be coordinated and used when the coordination of overcurrent

relays does not work. The distance relay is more costly than the overcurrent relay and requires the
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Figure 12-5: Open Differential

addition of line potential sources, adding cost to the scheme. Advantages of distance relays include a

fixed reach based on the impedance of the protected device, regardless of the system voltage and current

changes; the ability to operate at fault currents less than load current; and little transient overreach.

Two relays are used to protect the total length of the line, providing protection referred to as zones (see

Figure 12-6). Zone 1 relay is typically set for 85 to 95 percent of the line impedance. Zone 1 tripping

time is set for instantaneous tripping, that is, with no intentional time delay. Zone 2 is typically set to

120 to 150 percent of the line impedance. Zone 2 needs to extend past the line being protected into the

adjacent lines, not reaching past the far end terminal of the adjacent lines, yet ensuring the line in question

is covered. Zone 2 tripping time is typically set with 18 to 30 cycles of trip delay.

Figure 12-6: Distance Relay Zones 1 and 2

This scheme provides instantaneous tripping for 70 to 90 percent of the transmission line for a fault (F1,

Figure 12-6) located within Zone 1 reach for both ends of the line. For the remainder of the line, a fault

(F2, Figure 12-6) near each line terminal is cleared in the time delay used for Zone 2. A fault located near

a line terminal will be sequentially cleared by the near breaker tripping first and the remote terminal

breaker tripping after the Zone 2 trip time delay.
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A third zone of protection, Zone 3, is often used in step distance relaying. Zone 3 is usually set to reach

through the next line to cover breaker failures. The reach for the Zone 3 relay is usually in the range of

200 to 225 percent of the line impedance. Zone 3 tripping time is typically set with 60 to 120 cycles. The

impedance setting will vary depending on the length of the adjacent lines. Because of the reach of the

Zone 3 characteristic, it often encroaches on the load impedance and is susceptible to power system

swings. Use caution when incorporating Zone 3 relays since long settings can result in tripping on load.

Zone 3 may be reversed to look in the opposite direction of the line to which step distance relays are

being applied. This is the case when carrier schemes are applied. Occasionally, a reverse-set Zone 3

relay is used as a local breaker failure relay, indicating failure of adjacent circuit breakers.

Step distance relaying may be difficult to apply when the transmission lines are short, with little

impedance. The settings for the distance relays may be very small, near the limits of the design for the

relay reach, resulting in the possibility of the relay’s overreaching and tripping for adjacent line faults.

Three terminal lines will often use distance relays as fault detectors, but will normally require the

implementation of a pilot scheme to ensure tripping for all fault conditions.

12.4.2.2 Pilot Schemes: Pilot schemes simultaneously measure and monitor system parameters at all

terminals of a transmission line, local and remote, and then respond according to their predetermined

functions. These schemes require the use of a communications channel that may be provided through

pilot wires, microwave, fiber, or power line carrier. If the measured parameters exceed threshold values,

appropriate actions are initiated.

Pilot schemes can generally be broken into two primary categories. Those categories are directional

comparison and phase comparison. Directional schemes use directional distance relays for phase fault

detection and either directional distance relays or directional overcurrent relays for ground fault detection.

The decision to trip is based on relay setting thresholds being exceeded and the faults being located in the

predetermined direction for trip.

Phase comparison schemes are an extension of the differential protection principal. Currents from all line

terminals are converted into a composite signal, transmitted to the remote terminals, and compared to the

local terminal composite signal. The result of the comparison will result in a trip if the relay setting

threshold is exceeded. Phase comparison schemes are inherently directional and secure, not tripping for

faults outside the protected zone of protection.

12.4.2.2.1 Directional Comparison: Directional comparison schemes are divided into four

categories:

1. Blocking Schemes

Directional comparison blocking uses distance relays as directional indicators and block

initiation for phase faults. Either distance or directional overcurrent relays may be used for

ground fault indicators and block initiation. Each terminal has trip and start relays. The trip

relay reaches toward the remote terminal and a little beyond. The start relay reaches

backwards, away from the protected section. The trip relay attempts tripping when it operates

unless it is stopped by receipt of a blocking signal (carrier, audio tone, or microwave) from the

remote end. The start relays at each end initiate the blocking signal. Thus, if only the trip

relays see the fault, it is within the protected section and both ends trip. If the fault is just

outside one end, the start relays at that end operate and send a block signal to the remote end,

which would otherwise trip. The ground relays operate similarly.
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A tripping delay is necessary to allow for the receipt of the blocking signal. A typical delay

time of 6 to 16 msec is used to coordinate for the channel delay in communications. The

communication channel is not required for tripping the breakers since the breakers will trip in

the absence of the blocking signal. Failure of the channel could result in overtripping of the

breakers for adjacent line faults within the reach setting of the distance relays. Blocking

directional comparison is commonly used with on/off type carrier facilities. Since it is not

necessary to drive a signal through a fault to operate this scheme, it is the most popular carrier

relaying system. See Figure 12-7.

Figure 12-7: Blocking Directional Comparison

2. Unblocking Schemes

Directional comparison unblocking is similar to the blocking scheme except that the start

relays are deleted and the blocking, “guard” signal is sent continuously. See Figure 12-8. The

communication signal for an unblocking scheme uses a frequency shift keying (FSK) channel.

For an internal fault, the frequency is shifted to the unblock, “trip” frequency. The receivers

receive the trip frequency and close the output contact, which in series with the 21P relay

output contact will trip the breaker. For an external fault, within the reach of one of the 21P

relays, the distant 21P relay will see the fault while the local 21P relay will not see the fault

since it is behind the relay. The distant 21P relay will shift its transmitter frequency to trip.

The local 21P relay will not send the trip frequency or close the 21P output contacts. The line
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thus stays in service. Should the receivers fail to receive a guard signal and a trip signal, the

receivers will allow typically 150 msec of receiver contact closure to permit the 21P relay

contact to trip the line. After this time limit, the communication channel will lock out.

Figure 12-8: Directional Comparison Unblocking

This scheme is more secure since overtripping is avoided at all times with the exception of the

150-msec interval during the loss of signal. Reliability is improved since the communication

channel operates continuously and can be monitored, providing an alarm in the case of failure.

The scheme is applicable for two-terminal and multi-terminal lines. Separate channels are

required between each pair of line terminals.

3. Overreaching Transfer Trip Schemes

Permissive overreach is also a simple scheme, requiring only one overreaching fault detector

at each terminal. This fault detector sends both a trip signal and attempts local tripping

through a contact on the receiver. If both relays see a fault, both ends trip simultaneously.

The scheme appears similar to the directional comparison unblocking scheme of Figure 12-8.

A trip signal is required for this scheme to trip. Power line carrier channels therefore are not

recommended for these schemes since a fault could short out the carrier signal. These

channels are normally used with audio tones with frequency shift keying over microwave,

leased line, or fiber-optic communications.

The overreaching transfer trip scheme provides highly secure transmission line protection

since a trip signal is required from both ends of the line for tripping to occur. The

dependability of the scheme may be less than the blocking schemes since the trip signal has to

be received before the tripping is initiated. The scheme is often used when an existing nonpiloted scheme has communications added for piloting.
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4. Underreaching Transfer Trip Schemes

Underreaching transfer trip schemes include two variations: direct underreach and permissive

underreach.

The communications for this type of relaying are generally the same as for the overreaching

systems, using audio tones with frequency shift keying over microwave, leased line, or fiberoptic communications channels.

a. Direct Underreach

This form of protection requires only a single distance fault detector at each end. It has to

be set short of the remote end and will simultaneously trip the local breaker and send a

trip signal to the remote end, which then trips directly upon receipt of the signal. Note

that local confirmation is not required upon receipt of a trip signal. Though this scheme

is the least complex, it is seldom used because of the high risk of false outputs from the

communication channel, which would result in false trips. This risk can be minimized by

using a dual-channel transfer trip, which requires the receipt of two signals from the

remote end to effect a trip. See Figure 12-9.

Figure 12-9: Direct Underreach
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b. Permissive Underreach

This scheme is identical to the direct underreach scheme with the addition of an

overreaching fault detector. The transfer trip signal requires local confirmation by this

fault detector before tripping can occur. This increases the security of the scheme and the

consequent range of application. It is commonly selected when an existing step distance

relay line is to have the pilot added. See Figure 12-10. Carrier is not normally used since

a fault could short out the communication signal and prevent the signal from reaching the

remote terminal.

Figure 12-10: Permissive Underreach

12.4.2.2.2 Phase Comparison: Phase comparison relay systems monitor the current direction at each

line terminal of the protected line and transmit this information to the other terminal via a communication

channel. Each line terminal compares local and remote current direction and trips if the current is into the

line from both terminals. The communication channel is normally an on/off type of communications,

transmitting only when the overcurrent detector’s thresholds have been exceeded. This system is immune

to tripping on overloads or system swings since it operates on current direction only. It needs no potential

source unless it has to be supervised by distance relays because of low fault currents.

Current or distance fault detectors are used to supervise tripping. These detectors have to be set above

line charging current, which can appear to the relays as an internal fault at low loads. Internal timers have

to be set to compensate for the transit time of the communication channel. One of the most popular

applications of this system is on lines with series capacitors because it is less likely that such a currentoperated scheme will operate incorrectly for faults near the capacitors.
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1. Pilot Wire

This scheme is a form of phase comparison since it compares current direction at each

terminal. The difference between this scheme and others is that a pair of telephone wires is

used as the communication channel. A special filter in the relay converts the three-phase

currents to a single-phase voltage and applies this voltage to the wires. When current flows

through the protected section, the voltages at each end oppose each other and no current flows

in the operate coils. When current enters the line from each end, the voltage on the pilot wire

reverses to allow current to circulate through the operate coils and consequently trip both ends.

Special monitor relays sound an alarm if the pilot wire pair becomes open or shorted. The

wire line has to have adequate protection against induced voltages and a rise in station ground

potential but may not use carbon block protectors because the line has to remain in service

while the protection is operating. Neutralizing transformers and gas tubes with mutual

drainage reactors, all with adequate voltage ratings, comprise the preferred pilot wire

protection package.

This relaying has the advantage of simplicity and does not require a potential source. It does

not provide backup protection. Its application is limited to short lines a mile or so in length

because of pilot wire cost and increased exposure. The system’s dependability is based on the

integrity of the pilot wires themselves. Many pilot wire systems have been replaced with other

pilot schemes because of the failure of the pilot wire system to function reliably and securely.

Recently, pilot wire systems have been replaced with fiber-optic systems providing the

communications systems, using a module to convert the output voltage to a light signal. These

modified systems have provided a more dependable and secure protection system.

2. Single-Phase Comparison

This scheme applies a sequencing network to the current inputs to the relay to produce a

single-phase voltage output. This output is proportional to the positive, negative, and zero

phase sequence components of the input currents. This signal is squared so that the positive

portion of the signal provides the positive portion of the square wave. The negative portion of

the signal provides the zero portion of the square wave. Two fault detectors are normally used

to provide security, with the more sensitive detector used as the carrier start to transmit the

signal to the remote end. The less sensitive detector is used to arm the comparison module for

a trip upon the correct comparison of the local and remote signals. See Figure 12-11.

Normally current-operated units are used as the fault detectors. In a case where the fault

current is less than the load current, impedance-operated units may be used for fault detection.

The use of impedance fault detectors will increase the cost of the system because of the

necessity of having line potentials for the operation of the relay.

3. Dual-Phase Comparison

This scheme is similar to the single-phase comparison scheme except that square wave signals

are developed for the positive and the negative portions of the single-phase voltage output of

the sequencing network. Each signal requires a separate channel for the transmission of

information to the remote site. This scheme can provide a slightly higher speed of detection

since faults are detected on both the positive and the negative portions of the single-phase

voltage output of the sequencing network. This scheme is normally used with a frequencyshift channel, which is continuously transmitted. On a power line carrier it is configured as an

unblocking scheme.
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Figure 12-11: Single-Phase Comparison

4. Segregated Phase Comparison

This scheme is similar to the single-phase comparison scheme except that a square wave is

developed for each phase of the transmission line. A communication channel is required for

each phase to provide communications to the remote terminal. Comparisons are made on each
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of the three phases. The operation of the scheme is basically as described above in the

previous phase comparison schemes.

12.4.3 Distribution Feeder

Distribution line switching and protection within the substation are provided by circuit breakers,

reclosers, or fuses. The selection of the protective devices to be used on any particular feeder will depend

on the load being fed by the feeder, the magnitude of loads being served, any special protective

requirements necessitated by the load, and the cooperative’s preferences in design and operating

practices. In addition to the above-listed items, sectionalizers may be located on the distribution feeders

for additional segmenting of the line during fault conditions.

12.4.3.1 Circuit Breakers: Circuit breakers will most commonly use overcurrent relays to provide

fault protection at a substation. Historically, on a typical radial distribution feeder, two phase and one

ground (if the system is grounded) nondirectional inverse time overcurrent relays with instantaneous

elements will be the minimum relays that are applied that will detect all phase and ground faults when

properly coordinated. Often, a third overcurrent relay is applied to the phases. This will provide

complete protection for faults if one of the relays should be disabled. This also permits the removal of

one of the relays for testing outside the case, providing protection for the feeder without taking the feeder

out of service. With today’s microprocessor relays, three-phase relays and the neutral relay are applied to

detect all faults when properly coordinated. The time–current characteristic chosen for coordination of

protective devices will depend on what downstream devices are present on the feeder. See Figure 12-12.

Figure 12-12: Distribution Circuit Protective Elements
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Other protection may be provided in addition to overcurrent relays, such as voltage-controlled overcurrent

relays and negative sequence relays. Special circumstances on a feeder will allow specific relays to be

applied to address those circumstances. Microprocessor relays will often have a number of protective

functions available that may be used for special circumstances. Relay protection for circuit breakers may

be more readily customized and applied to special situations. Many of the microprocessor relays

available for distribution feeder protection also include multiple setting groups. This feature will allow a

relay to be set for a particular configuration. Should the configuration change, the setting group can be

changed, either automatically or manually, to provide for different settings to adjust the relay protection

to the new configuration.

12.4.3.2 Automatic Circuit Reclosers: Reclosers are devices similar to circuit breakers but more

compact and self-contained so that they may be used within the substation or mounted on poles out on the

distribution feeder. The controls permit various combinations of instantaneous and time-delayed trips and

automatic reclosures so that coordination may be accomplished with both upstream and downstream

devices. Reclosers may be single- or three-phase interrupters. Single-phase reclosers are series trip

devices, and three-phase reclosers may be either series trip or nonseries trip devices. Nonseries trip

reclosers usually employ a solid-state control and have a self-contained battery. Some single-phase

reclosers are available with electronic controls.

Single-phase reclosers usually provide better service reliability to rural distribution circuits because a

fault to ground on one phase will not trip the other phases. However, where loads are predominantly

three phase, or where the load on the circuit is large, three-phase reclosers with ground trip settings are

desirable to achieve the required sensitivity for ground faults.

Microprocessor controls are also available for reclosers. The microprocessor adds much flexibility to the

controller and provides additional functions, similar to many of the microprocessor relays. Also, many

additional protective characteristics (curves) are typically available in the microprocessor controls. There

is normally a communications port available on the control that can then provide data to remote sites.

12.4.3.2.1 Sectionalizers: These devices, located outside the substation on the distribution lines, are

similar to reclosers, except that they do not interrupt fault current. Instead, the sectionalizer counts trips

of an upstream recloser and opens its contacts during a de-energized period following a predetermined

number of recloser interruptions. Sectionalizers can, however, interrupt load currents within their rating.

See Figure 12-12.

12.4.3.2.2 Fuses: Fuses are used both to protect connected distribution transformers and to protect

sections or branches of the distribution circuit. Occasionally, they are used within the substation for

protection of a feeder or as backup protection for a bypass switch around a recloser or a breaker. They

are most commonly supplied in outdoor holders that are combination fuseholders and disconnect

switches. Fuses are usually applied as the farthest downstream device in a sectionalizing scheme because

of their nonrepeating nature. An upstream recloser trips and recloses several times with the accumulated

“on” time being sufficient to blow the fuse during a delayed trip. The recloser then resets before the trip

occurs.

12.4.3.2.3 Coordination: Coordinating these devices on a distribution circuit involves the progressive

disconnecting of sections of the distribution circuit beginning at the end farthest from the station until the

fault is removed. Since several different types of devices are involved, this process can be more complex

than coordinating a transmission line.
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Referring again to Figure 12-12, it may be seen that a fault at Fl should be interrupted by the fuse. This

means that the relay, recloser, and sectionalizer has to be programmed so that they will let enough

accumulated fault current through (integrated over several reclosures) that none of these devices locks

out. Generally, the recloser will have one fast and three delayed trips in such a situation. Time curves

will be selected so that the fuse will blow during the second delayed trip. The sectionalizer would be

programmed to open following the second delayed trip to clear a fault at F2. A fault at F3 would then be

cleared when the recloser locks out following the third (delayed) trip. The relay would be set to clear a

fault at F4 but coordinated with the line recloser so as not to trip for a fault at F3, paying careful attention

to overtravel and reset time of electromechanical reclosers following each successive interruption.

This is a simplified example of distribution coordination and ignores complications, such as long

branches and improperly applied protective devices, both common occurrences on real distribution

systems. In such cases, compromises have to be made and areas of nonselectivity accepted. The

coordination process involves moving these areas of nonselectivity into positions where they do the least

harm.

12.4.4 Major Equipment

12.4.4.1 Transformer and Reactor Protection: Transformers are protected by fuses or circuitinterrupting devices such as breakers or circuit switchers with relays detecting faults and providing trip

signals to the circuit-interrupting devices. Transformers 5 MVA and below are almost always protected

by fuses. Relay protection of transformers is most often used for transformers rated 10 MVA and above

although there are transformers up to 30 MVA that are protected by fuses.

Fuse protection has the merits of being economical and requiring little maintenance. Fuses require no

circuit-interrupting devices such as circuit breakers or circuit switchers and no battery power systems for

auxiliary power. Auxiliary equipment that would normally be located within a control building is

minimized, resulting in the reduced need for and cost of a control building. Fuses will provide protection

for primary and secondary external faults, but little protection for transformer internal faults. Fuses

introduce the probability of creating a severely unbalanced (single-phasing) voltage condition for

secondary loads should only one fuse blow. Proper coordination with secondary devices is essential to

avoid this condition.

Relay protection for the larger size transformers usually includes sudden pressure relays, differential

relays, overcurrent relays or directional phase distance relays, and ground overcurrent relays. See Figure 12-13. Sudden pressure relays are often considered by many to be the primary relay protection on a

transformer. The sudden pressure relay is sensitive to the sudden changes in pressure in the transformer

tank that occur during an internal fault. Differential protection is a primary scheme of protection that is

normally applied on a percentage differential basis to allow for differences in transformer ratios,

magnetizing current, and current transformer mismatch. Overcurrent relays are often applied on the

primary voltage winding to provide backup protection to the differential relay protection. If the

overcurrent relays may not be coordinated with the secondary main and feeder relays, a directional phase

distance relay may be applied. A ground overcurrent relay is normally applied to provide increased

sensitivity to ground faults.

Figure 12-13 indicates the possibility of using local primary and secondary breakers. Because of

economics, a primary breaker is sometimes not used. Tripping of the transformer is accomplished by

sending a transfer trip signal to the remote substation using a communications signal or a high-speed

ground switch. The time required to isolate the transformer is increased by the communication channel

time or the time for the remote relay and breaker to clear the fault established by the high-speed ground
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Figure 12-13: Typical Transformer Relay Protection
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Page 628

switch. Secondary breakers are often not used. The engineer will have to decide whether or not to trip all

the feeder breakers or to manually open the feeder breakers before re-energizing the transformer.

Reactors may be protected by generator-type differential relays with phase and ground overcurrent

backup relays. Occasionally, phase distance relays are used for backup.

Additional means of protection applied to transformers and reactors include negative sequence relays,

overvoltage relays, and thermal relays. Negative sequence relays can be set sensitively to back up

differential relays since they do not respond to load current. Overvoltage relays will protect the

transformer from excessive system voltage that will result in excessive transformer magnetizing current

and heating of the transformer core. Thermal relays provide additional protection for the transformer

against internal heating as a result of overloading the transformer.

Each transformer installation should be individually evaluated for the type of protection that is to be

applied.

12.4.4.2 Bus Protection

1. Remote Tripping for Bus Fault

Short-circuit faults on buses can be isolated by allowing remote substation breakers on all

lines that feed into the faulted bus to trip by Zone 2 or time-delay ground relay. This type of

bus protection is simple and the most economical. It has the disadvantage that any loads fed

by lines to the remote substations are also removed from service. Another disadvantage is that

the time necessary to clear the fault may be intolerable.

2. Local Tripping for Bus Fault

a. In distribution substations, the bus protection is often provided by overcurrent relays,

phase and neutral, located on either the low-voltage or high-voltage side of the

transformer. See Figure 12-13. The phase relays have to be set to coordinate with the

feeder relays and any additional downstream devices. This results in a slow trip time for

the clearing of the bus. Each bus has to be evaluated to determine if the time delay that

will be experienced by this type of protection will be excessive and if this type of

protection will be adequate. This bus protection scheme is very simple and may also be

able to act, in part, as backup protection to the feeder relays.

b. Short-circuit faults can be removed by a bus protective scheme in which all the substation

breakers associated with a faulted bus are tripped. The two basic types of bus protective

schemes are current differential and voltage differential. The current differential scheme

connects all the current transformers on all the circuits connected to a bus in parallel, and

the relays operate on the unbalanced current that exists during fault conditions. See

Figure 12-14. During normal conditions, there should be no unbalanced current, since

the current entering a bus has to equal the current leaving a bus. Restraint coils help to

compensate for unequal current transformer performance during external faults, but the

scheme still has to be applied carefully on buses with high short-circuit capabilities.

Voltage differential schemes use the same parallel connection but connect a highimpedance voltage element across the parallel. It is possible to set this voltage element

well above the worst case external fault voltage and still retain adequate sensitivity for

internal faults. This type of relay performs well on buses with high short-circuit

capability.
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Figure 12-14: Bus Differential Relay Protection

In some cases, overcurrent relays are applied to the differential circuit. This provides an

inexpensive relay for use in the operation of the differential circuit. The disadvantage of

the overcurrent relay is that there is no restraint in each of the relay circuits. Any

mismatch in the CTs has to be taken into consideration in the settings of the relay by

using a higher pickup amperage or a longer time delay. This will make the operation of

the circuit slower than the times provided by differential relays. Many times this time

delay is unacceptable for the coordination with the rest of the system relays.

c. Since the recent use of the microprocessor relay that normally provides additional

functions at a relatively inexpensive cost, a pseudo bus differential scheme has been

applied. This scheme uses a combination of instantaneous relay elements from the

secondary main bus relay and the feeder relays to detect whether the fault is on the feeder

or on the bus. See Figure 12-15. This scheme requires that there be no fault sources on

the feeders since the operation of the feeder instantaneous elements for reverse feeder

current would make the fault look like a feeder fault and cause the scheme to fail. If fault

sources are located on the feeders, directional instantaneous overcurrent relays have to be

used. An instantaneous element is used on the main breaker relay with a setting that is

ensured to pick up any bus fault. The instantaneous elements of the feeder relays have to

be set to reach out farther than the main breaker relay so that, for any close-in feeder fault

that the main breaker relay will see, the feeder relay will also see and disable the circuit.

For a bus fault, the feeders will not see the fault so the relay takes no action. The main

breaker relay sees the fault, closes its contact, and, after the appropriate time delay, trips

the breaker. This circuit will be slower than an actual differential relay circuit operating

time, but will be faster than the overcurrent relay in protecting the bus from damage.
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Figure 12-15: Pseudo Bus Differential Circuit

d. Local tripping for a bus fault may be accomplished by the use of a reverse-looking

Zone 3 element from a distance relay. Zones 1 and 2 on a line are set to look out on the

line, away from the bus. Often, the Zone 3 element is set to look in the reverse direction,

which will see the bus behind it. Through a timer, the Zone 3 may be set to trip throughbus faults.

12.4.4.3 Breaker Failure Protection: Breaker failures can normally be separated into two classes:

the failure of the breaker itself and the failure of the relaying associated with the breaker. Schemes

developed to protect for the failure of breakers are based on providing either remote backup or local

backup. Failure of the breaker results in the necessity to trip all the adjacent breakers in order to clear the

fault and to isolate the failed breaker.

1. Remote Backup

Remote backup normally consists of a Zone 3 distance relay and/or ground time overcurrent

relay set to cover lines contiguous to the line being protected. This scheme will provide

protection for breaker failure regardless of whether the failure is a result of relay failure or

breaker failure. It will normally see faults on the protected line plus faults on the next bus and

line adjacent to the protected line. This scheme has the advantage of simplicity.

Complications in using the scheme include that the relay has to be set above the maximum

load current that is carried on the lines, yet it has to be set sensitively enough to see the faults

that may occur on the lines. Faults occurring at the remote ends of the lines may not be

detected because of insufficient current flow. When applied on a system where the adjacent
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bus has a number of lines with varying length, the settings for the relay may extend beyond the

adjacent lines resulting in overcoverage and overtripping. When adjacent lines are multiterminal lines, a number of terminals may be unnecessarily tripped by remote backup. Longer

reach Zone 3 relays are more susceptible to out-of-step system swings. Even with its

shortcomings, in some situations with its inherent economics, this scheme may provide

acceptable backup performance.

2. Local Backup

a. A simple means of providing local backup protection is to use the Zone 3 relay looking in

the reverse direction. This provides a degree of protection for local equipment including

all adjacent breakers, bus, lines, and remote terminals. Advantages and disadvantages in

the use of this scheme are included in the discussion above on remote backup.

b. An additional means of providing breaker protection is to add timing to the primary

relays. If the relays do not trip and the fault is still on the system within the set time of

the timer, the timer will act to trip all adjacent breakers. This scheme depends on the

proper action of the primary relays and provides no backup to the failure of those relays.

c. An additional scheme provides the use of a second set of relays to back up the primary

relaying. Carried to the maximum limit, a second dc tripping system is provided

including battery, panels, charger, relays, breaker trip coils, CTs, and potential devices.

This degree of duplication is occasionally provided for EHV systems. Higher voltage

systems including 69 kV and above will often provide dual trip coils in the circuit

breakers, and primary and secondary relays with dual dc trip buses. The engineer has to

decide if auxiliary dc power systems will be duplicated, including power panels and

chargers; often both systems are fed from a common battery. The reduced cost of

relaying afforded by the development of microprocessor relays makes this option a

relatively economical option to provide backup protection for relays. This scheme does

not provide for the tripping of adjacent breakers in the case of the failure of the breaker

mechanical mechanism to trip the breaker and clear the fault.

d. Full breaker failure backup includes protection for the failure of relays and the failure of

the breaker. A separate backup relay that acts to trip all adjacent breakers, including

remote breakers by means of a transfer trip, provides this degree of backup. Figure 12-16

indicates a typical configuration for a local breaker failure relay. Indicated are primary

and secondary relays, dual trip coils in the breaker, and the fault detector and timer

associated with the breaker relay. Should either the primary or secondary relay call for a

trip of the breaker, an auxiliary relay, 62X or 62Y, keys the timer. If the fault is not

removed during the setting for the timer, the 86BF lockout relay is picked up to trip all

adjacent breakers and transfer trip any remote breakers. The time setting for the timer is

usually in the range of 10 to 20 cycles. If either the protective scheme resets or the

current relay drops out within the set time, nothing happens.

12.4.5 Reclosing

12.4.5.1 General: Protective relays detect faults or abnormal conditions. These faults or abnormal

conditions can be transient or permanent. For open-wire overhead circuits, such as most of the

distribution lines, most faults are transient faults, caused for example by lightning, that can be cleared by

disconnecting the circuit from the power source. Service can be restored by reclosing the disconnecting
Bulletin 1724E-300

Page 632

Figure 12-16: Typical Breaker Failure Relay Scheme

device. Certain abnormal conditions, such as overheating of motors, can be relieved by reducing the load

on the motor. The motor starters thus can be safely reclosed after the motor has cooled off. The

disconnecting device can be reclosed either manually or automatically. Manual reclosing is performed by

following the same procedures used in closing the device. Automatic reclosing is usually performed by

automatic reclosing relays. Reclosing is generally not applied where permanent faults are more likely,

such as on cables.
Bulletin 1724E-300

Page 633

12.4.5.2 Automatic Reclosing Relays: Automatic reclosing relays permit the circuit disconnecting

device, usually a breaker, to close one or more times when the breaker has been tripped by protective

relays. Relays that permit one reclosing operation are called single-shot reclosing relays, while relays that

permit more than one reclosing operation are called multishot reclosing relays. Single-shot reclosing

relays can be either the manual- or self-reset type. The manual-reset types have to be manually reset after

each automatic reclosing operation to obtain succeeding automatic reclosing operations. The self-reset

types automatically reset if the breaker remains closed for a predetermined time. Multishot reclosing

relays are of the self-reset type. Automatic reclosing can take place either instantaneously or with time

delay, when the line is de-energized or energized, or when the voltages on both sides of the breaker are

synchronized. On radial circuits, the first reclosure is usually instantaneous, with additional reclosures,

when used, taking place after some time delay. On loop or multiterminal distribution lines, instantaneous

reclosing is generally not used unless special forms of protective relaying are applied to ensure

simultaneous operation of all line breakers for all line faults. After a specified number of unsuccessful

automatic reclosure attempts, the breaker is usually locked open.

12.4.6 Coordination

When a circuit element such as a line, transformer, or bus becomes faulted, it has to be removed from

service. This, as has been previously stated, is the function of the protective relay system. Coordination

is the process of ensuring that only those elements of the power system that has to be removed to clear the

fault, and no more, are tripped in the shortest time possible.

As previously discussed, some schemes are inherently selective in tripping the protected equipment. Such

protection schemes include differential schemes and transmission line phase protection that are

differential in nature. No additional coordination is required for these schemes.

Coordination with distance relays is the easiest to accomplish. Since such a relay’s reach is constant

under all system conditions, the instantaneous zone is typically set short of the remote end of the line by

10 percent, and it will never trip for any condition but a fault on the protected section. With the remote

end set the same, 80 percent of the line is thus covered by instantaneous protection. To cover the

remaining 20 percent, the second zone can be relied on or a piloted scheme can be added. The second

zone reaches beyond the protected section and so it has to have a time delay to allow the breaker at the

remote station to clear a fault on another line. The third zone reaches beyond the remote second zones

and so has to time coordinate in the same manner, thus the increasing time settings.

Coordinating with overcurrent relays can be more difficult and can also require a more detailed

knowledge of system parameters.

For the simple system shown in Figure 12-17, with a fault at X, the near relays at C and D has to operate

and their breakers have to be completely open before the remote or backup relays at A and F close their

contacts. It is assumed that:

1. A faulted condition exists until the breakers isolating the fault are entirely open.

2. When a relay closes its tripping contacts, a “seal-in” auxiliary relay ensures that the switching

operation will be completed even though the fault is cleared at the same instant the relay

contacts close.
Bulletin 1724E-300

Page 634

Figure 12-17: Coordination Conditions

The time delay of the remote relay necessary for selectivity has to be equal to the operating time of the

near relay plus the opening time of the breaker; plus a reasonable factor of safety, which can be taken at

about 25 percent of the combined relay and breaker time with a minimum allowance of not less than six

cycles if the relays are normally field calibrated at the calculated setting. If the relays are bench tested at

typical setting values and only adjusted in the field with no further calibration, this margin has to be

greater, typically 0.2 to 0.3 seconds.

Additional requirements for adequate relay coordination include the following:

1. The relays have to be capable of carrying a reasonable emergency overload without tripping

incorrectly on load current.

2. The relays have to be able to operate under minimum system generating conditions for faults

at the far ends of the sections that they protect.

Maximum system generating conditions include a sufficient number of generators in service to supply the

maximum demand load of the system. Similarly, the minimum system generating conditions include only

the generators in service necessary to supply the minimum system load. Such minimum conditions would

probably exist early Sunday mornings, for example. In addition to the above generation, there are usually

some emergency generators in service called “spinning reserve” that can immediately pick up load if a

generator fails. Both maximum and minimum conditions have to be checked, since maximum generation

usually results in faster operation of induction-type relays with more critical selectivity, and the minimum

condition determines whether the relays will receive sufficient current to operate.

The output of a synchronous generator under fault conditions is variable, depending on the characteristics

of the machine and the duration of the fault. The initial output, which is maintained for three cycles or

less, may be four to ten times the normal machine rating and is determined by the subtransient reactance.

The generator output rapidly decreases to the value determined by transient reactance, the average value

of which may be assumed to exist for about 30 cycles on turbine generators and up to 120 cycles on

condensers and slow-speed generators. The transient reactance may be taken roughly as 125 percent to

150 percent of the subtransient reactance. If the fault is not cleared, the generator output approaches the

synchronous value, which is equal to or slightly less than the normal rating. It is the common practice,

therefore, to use generator subtransient reactance values when calculating maximum fault kVA and to use

transient values for minimum generating conditions. Synchronous values of short-circuit kVA are not

usually calculated, but the decrease in generator output should be considered for slow operating relays.
Bulletin 1724E-300

Page 635

For ground current calculations and determination of selectivity for ground relays, it is customary to show

only the maximum fault conditions on transmission systems. On transmission systems where the relative

distribution of ground fault current is changed for minimum generation because grounded transformers

have been removed from service, it may be necessary to calculate and check the relay settings for both

maximum and minimum ground faults. It may also be necessary to show minimum ground faults for

some special conditions with certain lines or transformer banks out of service.

Briefly summarized, the job of the relay engineer is to assume various types of faults at numerous points

on a system. The magnitude and distribution of fault currents are then calculated for these fault points

with maximum and minimum generating conditions. Faults are assumed for normal system operating

conditions and for various special conditions with certain lines, generators, or transformers out of service.

The operating time of all breakers involved have to be checked and tabulated and, for high burdens or low

ratios, the true or effective ratios of bushing-type current transformers have to be determined. Having

obtained these data, the next step is to determine suitable settings or adjustments for the relays that will

provide selective operation for each fault condition. The tentative relay settings, the calculated current

values, and the operating times of the near and remote relays for each fault condition are worked up and

recorded as “Details of Selectivity” or on “Selectivity Curves.” After the most satisfactory settings are

determined, “Summary Sheets” are made up for all the relays at each station. The Summary Sheets have

the instructions or calibration data to enable the relay personnel in the field to set or adjust the relays to

obtain the desired operating characteristics.

12.5 REFERENCES

Blackburn, J. Lewis, Protective Relaying Principles and Applications, New York: Marcel Dekker, Inc.,

1987.

IEEE Std. C37.2, “IEEE Standard Electrical Power System Device Function Numbers and Contact

Designations.”

Institute of Electrical and Electronic Engineers, Inc., IEEE Guides and Standards for Protective Relaying

Systems, New York: IEEE, 1992.

Institute of Electrical and Electronic Engineers, Protective Relaying for Power Systems, New York: IEEE,

1980.

Institute of Electrical and Electronic Engineers, Protective Relaying for Power Systems II, New York:

IEEE, 1992.

Mason, C.R., The Art and Science of Protective Relaying, New York: John Wiley and Sons, Inc., 1956.

McGraw Edison Company, Power Systems Division, Distribution System Protection Manual,

Canonsberg, Pa.: McGraw-Edison Co., 1972.

St. Leonards Works, GEC Measurements, Marketing Department, Protective Relays Application Guide,

Stafford ST147LX, England: St. Leonards Works, 1987.

Warrington, Van C., Protective Relays: Their Theory and Practice, 2d ed., London: Chapman and Hall

Ltd., 1968.
Bulletin 1724E-300

Page 636

Westinghouse Electric Corporation, Applied Protective Relaying, Newark, N.J.: Westinghouse, 1976.
Bulletin 1724E-300

Appendix F

Page 637

COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

APPENDIX F

STANDARD DEVICE FUNCTION NUMBERS

The following Standard Device Function Numbers are reprinted from IEEE Std. 37.2-1996, “IEEE

Standard Electrical Power System Device Numbers and Contact Designations,” Copyright © 1996 by the

Institute of Electrical and Electronics Engineers, Inc. The IEEE disclaims any responsibility or liability

resulting from the placement and use in the described manner. Information is reprinted with the

permission of the IEEE.

Device Definition

Number and Function 

1 Master Element is a device, such

as a control switch, etc., that serves,

either directly or through such

permissive devices as protective and

time-delay relays, to place

equipment in or out of operation.

NOTE-This number is normally

used for a hand-operated device,

although it may also be used for an

electrical or mechanical device for

which no other function number is

suitable.

2 Time-delay starting or closing

relay is a device that functions to

give a desired amount of time delay

before or after any point of

operations in a switching sequence

or protective relay system, except as

specifically provided by device

functions 48, 62, 79, and 82.

3 Checking or interlocking relay is a

device that operates in response to

the position of one or more other

devices or predetermined conditions

in a piece of equipment or circuit, to

allow an operating sequence to

proceed, or to stop, or to provide a

check of the position of these

devices or conditions for any

purpose.

4 Master contactor is a device,

generally controlled by device

function 1 or the equivalent and the

required permissive and protective

devices, that serves to make and

Device Definition

Number and Function 

break the necessary control circuits

to place equipment into operation

under the desired conditions and to

take it out of operation under

abnormal conditions.

5 Stopping device is a control device

used primarily to shut down equipment and hold it out of operation.

(This device may be manually or

electrically actuated, but it excludes

the function of electrical lockout

[see device function 86] on

abnormal conditions.)

6 Starting circuit breaker is a device

whose principal function is to

connect a machine to its source of

starting voltage.

7 Rate-of-change relay is a device

that operates when the rate-ofchange of the measured quantity

exceeds a threshold value except as

defined by device 63 (see 3.1.63).

8 Control power disconnecting

device is a device, such as a knife

switch, circuit breaker, or pull-out

fuse block, used for the purpose of

connecting and disconnecting the

source of control power to and from

the control bus or equipment.

NOTE-Control power is considered

to include auxiliary power that

supplies such apparatus as small

motors and heaters.

9 Reversing device is a device that is
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COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

used for the purpose of reversing a

machine field or for performing any

other reversing function.

10 Unit sequence switch is a device

that is used to change the sequence

in which units may be placed in and

out of service in multiple-unit

equipment.

11 Multifunction device is a device

that performs three or more

comparatively important functions

that could only be designated by

combining several device function

numbers. All of the functions

performed by device 11 shall be

defined in the drawing legend,

device function definition list or

relay setting record. See Annex B

for further discussion and examples.

NOTE-If only two relatively

important functions are performed

by the device, it is preferred that

both function numbers can be used

as described in 3.6.

12 Overspeed device is a device,

usually direct connected, that

operates on machine overspeed.

13 Synchronous-speed device is a

device such as a centrifugal-speed

switch, a slip frequency relay, a

voltage relay, an undercurrent relay,

or any other type of device that

operates at approximately the

synchronous speed of a machine.

14 Underspeed device is a device that

functions when the speed of a

machine falls below a

predetermined value.

15 Speed or frequency matching

device is a device that functions to

match and hold the speed or

frequency of a machine or a system

equal to, or approximately equal to,

that of another machine, source, or

system.

16 Reserved for future application.

17 Shunting or discharge switch is a

device that serves to open or close a

shunting circuit around any piece of

apparatus (except a resistor), such as

a machine field, a machine

armature, a capacitor, or a reactor.

NOTE-This excludes devices that

perform such shunting operations as

may be necessary in the process of

starting a machine by devices 6 or

42 (or their equivalent) and also

excludes device function 73 that

serves for the switching of resistors.

18 Accelerating or decelerating

device is a device that is used to

close or cause the closing of circuits

that are used to increase or decrease

the speed of a machine.

19 Starting-to-running transition

contactor is a device that operates

to initiate or cause the automatic

transfer of a machine from the

starting to the running power

connection.

20 Electrically operated valve is an

electrically operated, controlled, or

monitored device used in a fluid, air,

gas, or vacuum line.

NOTE-The function of the valve

may be more completely indicated

by the use of suffixes as discussed

in 3.2.
Bulletin 1724E-300

Appendix F

Page 639

COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

21 Distance relay is a device that

functions when the circuit

admittance, impedance, or reactance

increases or decreases beyond a

predetermined value.

22 Equalizer circuit breaker is a

device that serves to control or make

and break the equalizer or the

current-balancing connections for a

machine field, or for regulating

equipment, in a multiple-unit

installation.

23 Temperature control device is a

device that functions to control the

temperature of a machine or other

apparatus, or of any medium, when

its temperature falls below or rises

above a predetermined value.

NOTE-An example is a thermostat

that switches on a space heater in a

switchgear assembly when the

temperature falls to a desired value.

This should be distinguished from a

device that is used to provide

automatic temperature regulation

between close limits and would be

designated as device function 90T.

24 Volts per hertz relay is a device

that operates when the ratio of

voltage to frequency is above a

preset value. The relay may have

any combination of instantaneous or

time delayed characteristics.

25 Synchronizing or synchronismcheck relay is a synchronizing

device that produces an output that

causes closure at zero-phase angle

difference between two circuits. It

may or may not include voltage and

speed control. A synchronismcheck relay permits the paralleling

of two circuits that are within

prescribed limits of voltage

magnitude, phase angle, and

frequency.

26 Apparatus thermal device is a

device that functions when the

temperature of the protected

apparatus (other than the loadcarrying windings of machines and

transformers as covered by device

function number 49) or of a liquid

or other medium exceeds a

predetermined value; or when the

temperature of the protected

apparatus or of any medium

decreases below a predetermined

value.

27 Undervoltage relay is a device that

operates when its input voltage is

less than a predetermined value.

28 Flame detector is a device that

monitors the presence of the pilot or

main flame in such apparatus as a

gas turbine or a steam boiler.

29 Isolating contactor or switch is a

device that is used expressly for

disconnecting one circuit from

another for the purposes of

emergency operation, maintenance,

or test.

30 Annunciator relay is a

nonautomatically reset device that

gives a number of separate visual

indications upon the functioning of

protective devices and that may also

be arranged to perform a lockout

function.

31 Separate excitation device is a

device that connects a circuit, such

as the shunt field of a synchronous
Bulletin 1724E-300

Appendix F

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COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

converter, to a source of separate

excitation during the starting

sequence.

32 Directional power relay is a device

that operates on a predetermined

value of power flow in a given

direction such as reverse power flow

resulting from the motoring of a

generator upon loss of its prime

mover.

33 Position switch is a device that

makes or breaks contact when the

main device or piece of apparatus

that has no device function number

reaches a given position.

34 Master sequence device is a device

such as a motor-operated multicontact switch, or the equivalent, or

a programmable device, that

establishes or determines the

operating sequence of the major

devices in equipment during starting

and stopping or during sequential

switching operations.

35 Brush-operating or slip-ring

short-circuiting device is a device

for raising, lowering, or shifting the

brushes of a machine; shortcircuiting its slip rings; or engaging

or disengaging the contacts of a

mechanical rectifier.

36 Polarity or polarizing voltage

device is a device that operates, or

permits the operation of, another

device on a predetermined polarity

only or that verifies the presence of

a polarizing voltage in equipment.

37 Undercurrent or underpower

relay is a device that functions

when the current or power flow

decreases below a predetermined

value.

38 Bearing protective device is a

device that functions on excessive

bearing temperature or on other

abnormal mechanical conditions

associated with the bearing, such as

undue wear, which may eventually

result in excessive bearing

temperature or failure.

39 Mechanical condition monitor is a

device that functions upon the

occurrence of an abnormal

mechanical condition (except that

associated with bearings as covered

under device function 38), such as

excessive vibration, eccentricity,

expansion, shock, tilting, or seal

failure.

40 Field relay is a device that

functions on a given or abnormally

high or low value or failure of

machine field current, or on an

excessive value of the reactive

component of armature current in an

ac machine indicating abnormally

high or low field excitation.

41 Field circuit breaker is a device

that functions to apply or remove

the field excitation of a machine.

42 Running circuit breaker is a

device whose function is to connect

a machine to its source of running or

operating voltage. This function

may also be used for a device, such

as a contactor, that is used in series

with a circuit breaker or other faultprotecting means, primarily for
Bulletin 1724E-300

Appendix F

Page 641

COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

frequent opening and closing of the

circuit.

43 Manual transfer or selector device

is a manually operated device that

transfers control or potential circuits

in order to modify the plan of

operation of the associated

equipment or of some of the

associated devices.

44 Unit sequence starting relay is a

device that functions to start the

next available unit in multiple-unit

equipment upon the failure or nonavailability of the normally

preceding unit.

45 Atmospheric condition monitor is

a device that functions upon the

occurrence of an abnormal

atmospheric condition, such as

damaging fumes, explosive

mixtures, smoke, or fire.

46 Reverse-phase or phase-balance

current relay is a device in a

polyphase circuit that operates when

the polyphase currents are of

reverse-phase sequence or when the

polyphase currents are unbalanced

or when the negative phasesequence current exceeds a preset

value.

47 Phase-sequence or phase-balance

voltage relay is a device in a

polyphase circuit that functions

upon a predetermined value of

polyphase voltage in the desired

phase sequence, when the polyphase

voltages are unbalanced, or when

the negative phase-sequence voltage

exceeds a preset value.

48 Incomplete sequence relay is a

device that generally returns the

equipment to the normal or off

position and locks it out if the

normal starting, operating, or

stopping sequence is not properly

completed within a predetermined

time.

49 Machine or transformer thermal

relay is a device that functions

when the temperature of a machine

armature winding or other loadcarrying winding or element of a

machine or power transformer

exceeds a predetermined value.

50 Instantaneous overcurrent relay is

a device that operates with no

intentional time delay when the

current exceeds a preset value.

51 AC time overcurrent relay is a

device that functions when the ac

input current exceeds a

predetermined value, and in which

the input current and operating time

are inversely related through a

substantial portion of the

performance range.

52 AC circuit breaker is a device that

is used to close and interrupt an ac

power circuit under normal

conditions or to interrupt this circuit

under fault or emergency

conditions.

53 Exciter or dc generator relay is a

device that forces the dc machine

field excitation to build up during

starting or that functions when the

machine voltage has built up to a

given value.

.
Bulletin 1724E-300

Appendix F

Page 642

COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

54 Turning gear engaging device is a

device either electrically operated,

controlled, or monitored that

functions to cause the turning gear

to engage (or disengage) the

machine shaft

55 Power factor relay is a device that

operates when the power factor in

an ac circuit rises above or falls

below a predetermined value.

56 Field application relay is a device

that automatically controls the

application of the field excitation to

an ac motor at some predetermined

point in the slip cycle.

57 Short-circuiting or grounding

device is a device that functions to

short-circuit or ground a circuit in

response to automatic or manual

means.

58 Rectification failure relay is a

device that functions if a power

rectifier fails to conduct or block

properly.

59 Overvoltage relay is a device that

operates when its input voltage

exceeds a predetermined value.

60 Voltage or current balance relay

is a device that operates on a given

difference in voltage, or current

input or output, of two circuits.

61 Density switch or sensor is a

device that operates at a given

density value or at a given rate of

change of density.

62 Time-delay stopping or opening

relay is a device that imposes a time

delay in conjunction with the device

that initiates the shutdown, stopping,

or opening operation in an

automatic sequence or protective

relay system.

63 Pressure switch is a device that

operates at a given pressure value or

at a given rate of change of pressure.

64 Ground detector relay is a device

that operates upon failure of

machine or other apparatus

insulation to ground.

NOTE-This function is not applied

to a device connected in the

secondary circuit of current

transformers in a normally grounded

power system where other

overcurrent device numbers with the

suffix G or N should be used; for

example, 51N for an ac time

overcurrent relay connected in the

secondary neutral of the current

transformers.

65 Governor is a device consisting of

an assembly of fluid, electrical, or

mechanical control equipment used

for regulating the flow of water,

steam, or other media to the prime

mover for such purposes as starting,

holding speed or load, or stopping.

66 Notching or jogging device is a

device that functions to allow only a

specified number of operations of a

given device or piece or equipment,

or a specified number of successive

operations within a given time of

each other. It is also a device that

functions to energize a circuit

periodically or for fractions of

specified time intervals, or that is

used to permit intermittent
Bulletin 1724E-300

Appendix F

Page 643

COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

acceleration or jogging of a machine

at low speeds for mechanical

positioning.

67 AC directional overcurrent relay

is a device that functions at a

desired value of ac overcurrent

flowing in a predetermined

direction.

68 Blocking or “out-of-step” relay is

a device that initiates a pilot signal

for blocking of tripping on external

faults in a transmission line or in

other apparatus under predetermined

conditions, or cooperates with other

devices to block tripping or

reclosing on an out-of-step

condition or on power swings.

69 Permissive control device is a

device with two positions that in one

position permits the closing of a

circuit breaker, or the placing of a

piece of equipment into operation,

and in the other position, prevents

the circuit breaker or the equipment

from being operated.

70 Rheostat is a device used to vary

the resistance in an electric circuit

when the device is electrically

operated or has other electrical

accessories, such as auxiliary,

position, or limit switches.

71 Level switch is a device that

operates at a given level value, or on

a given rate of change of level.

72 DC circuit breaker is a device that

is used to close and interrupt a dc

power circuit under normal

conditions or to interrupt this circuit

under fault or emergency

conditions.

73 Load-resistor contactor is a device

that is used to shunt or insert a step

of load limiting, shifting, or

indicating resistance in a power

circuit; to switch a space heater in

circuit; or to switch a light or

regenerative load resistor of a power

rectifier or other machine in and out

of circuit.

74 Alarm relay is a device other than

an annunciator, as covered under

device function 30, that is used to

operate, or that operates in

connection with, a visual or audible

alarm.

75 Position changing mechanism is a

device that is used for moving a

main device from one position to

another in equipment; for example,

shifting a removable circuit breaker

unit to and from the connected,

disconnected, and test positions.

76 DC overcurrent relay is a device

that functions when the current in a

dc circuit exceeds a given value.

77 Telemetering device is a

transmitting device used to generate

and transmit to a remote location an

electrical signal representing a

measured quantity; or a receiver

used to receive the electrical signal

from a remote transmitter and

convert the signal to represent the

original measured quantity.

78 Phase-angle measuring relay is a

device that functions at a

predetermined phase angle between

two voltages, between two currents,

or between voltage and current.
Bulletin 1724E-300

Appendix F

Page 644

COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

79 Reclosing relay is a device that

controls the automatic reclosing and

locking out of an ac circuit

interrupter.

80 Flow switch is a device that

operates at a given flow value, or at

a given rate of change of flow.

81 Frequency relay is a device that

responds to the frequency of an

electrical quantity, operating when

the frequency or rate of change of

frequency exceeds or is less than a

predetermined value.

82 DC load-measuring reclosing

relay is a device that controls the

automatic closing and reclosing of a

dc circuit interrupter, generally in

response to load circuit conditions.

83 Automatic selective control or

transfer relay is a device that

operates to select automatically

between certain sources or

conditions in equipment or that

performs a transfer operation

automatically.

84 Operating mechanism is a device

consisting of the complete electrical

mechanism or servomechanism,

including the operating motor,

solenoids, position switches, etc.,

for a tap changer, induction

regulator, or any similar piece of

apparatus that otherwise has no

device function number.

85 Carrier or pilot-wire relay is a

device that is operated or restrained

by a signal transmitted or received

via any communications media used

for relaying.

86 Lockout relay is a device that trips

and maintains the associated

equipment or devices inoperative

until it is reset by an operator, either

locally or remotely.

87 Differential protective relay is a

device that operates on a percentage,

phase angle, or other quantitative

difference of two or more currents

or other electrical quantities.

88 Auxiliary motor or motor

generator is a device used for

operating auxiliary equipment, such

as pumps, blowers, exciters, rotating

magnetic amplifiers, etc.

89 Line switch is a device used as a

disconnecting, load-interrupter, or

isolating switch in an ac or dc power

circuit. (This device function

number is normally not necessary

unless the switch is electrically

operated or has electrical

accessories, such as an auxiliary

switch, a magnetic lock, etc.)

90 Regulating device is a device that

functions to regulate a quantity or

quantities, such as voltage, current,

power, speed, frequency,

temperature, and load, at a certain

value or between certain (generally

close) limits for machines, tie lines,

or other apparatus.

91 Voltage directional relay is a

device that operates when the

voltage across an open circuit

breaker or contactor exceeds a given

value in a given direction.

92 Voltage and power directional

relay is a device that permits or
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Appendix F

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COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Device Definition Device Definition

Number and Function Number and Function 

causes the connection of two

circuits when the voltage difference

between them exceeds a given value

in a predetermined direction and

causes these two circuits to be

disconnected from each other when

the power flowing between them

exceeds a given value in the

opposite direction.

93 Field-changing contactor is a

device that functions to increase or

decrease, in one step, the value of

field excitation on a machine.

94 Tripping or trip-free relay is a

device that functions to trip a circuit

breaker, contactor, or equipment; to

permit immediate tripping by other

devices; or to prevent immediate

reclosing of a circuit interrupter if it

should open automatically, even

though its closing circuit is

maintained closed.

95-99 These device numbers are used in

individual specific installations if

none of the functions assigned to the

numbers 1 through 94 are suitable.
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Appendix G

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COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

APPENDIX G

SUGGESTED SUFFIX LETTERS

These Suggested Suffix Letters are reprinted from IEEE Std. 37.2-1996, “IEEE Standard Electrical Power

System Device Numbers and Contact Designations,” Copyright © 1997 by the Institute of Electrical and

Electronics Engineers, Inc. The IEEE disclaims any responsibility or liability resulting from the

placement and use in the described manner. Information is reprinted with the permission of the IEEE.

Auxiliary devices

These letters denote separate auxiliary devices, such as the following:

C Closing relay/contactor

CL Auxiliary relay, close (energized when main device is in closed position)

CS Control switch

D “Down” position switch relay

L Lowering relay

O Opening relay/contactor

OP Auxiliary relay, open (energized when main device is in open position)

PB Push button

R Raising relay

U “UP” position switch relay

X Auxiliary relay

Y Auxiliary relay

Z Auxiliary relay

NOTE-In the control of a circuit breaker with a so-called X-Y relay control scheme, the X relay is the

device whose main contacts are used to energize the closing coil or the device that in some other manner,

such as by the release of stored energy, causes the breaker to close. The contacts of the Y relay provide

the antipump feature of the circuit breaker.

Actuating quantities

These letters indicate the condition or electrical quantity to which the device responds, or the medium in

which it is located, such as the following:

A Air/amperes/alternating

C Current

D Direct/discharge

E Electrolyte

F Frequency/flow/fault

GP Gas pressure

H Explosive/harmonics

I0 Zero sequence current

I–, I2 Negative sequence current

I+, I1 Positive sequence current

J Differential

L Level/liquid

P Power/pressure

PF Power factor

O Oil

S Speed/suction/smoke

T Temperature
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Appendix G

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COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

V Voltage/volts/vacuum

VAR Reactive power

VB Vibration

W Water/watts

Main device

The following letters denote the main device to which the numbered device is applied or is related:

A Alarm/auxiliary power

AC Alternating current

AN Anode

B Battery/blower/bus

BK Brake

BL Block (valve)

BP Bypass

BT Bus tie

C Capacitor/condenser/compensator/carrier current/case/compressor

CA Cathode

CH Check (valve)

D Discharge (valve)

DC Direct current

E Exciter

F Feeder/field/filament/filter/fan

G Generator/ground1

H Heater/housing

L Line/logic

M Motor/metering

MOC Mechanism operated contact2

N Network/neutral3

P Pump/phase comparison

R Reactor/rectifier/room

S Synchronizing/secondary/strainer/sump/suction (valve)

T Transformer/thyratron

TH Transformer (high-voltage side)

TL Transformer (low-voltage side)

TM Telemeter

TOC Truck-operated contacts4

TT Transformer (tertiary-voltage side)

U Unit

 

1

 Suffix N is preferred when the device is connected in the residual of a polyphase circuit, is connected across a

broken delta, or is internally derived from the polyphase current or voltage quantities. The suffix G is preferred

where the measured quantity is in the path to ground or, in the case of ground fault detectors, is the current flowing

to ground. See A.2 in Annex A for examples.

2

 MOC denotes a circuit breaker mechanism-operated auxiliary switch that is mounted on the stationary housing of a

removable circuit breaker.

3

 See Footnote 1.

4

 TOC denotes a circuit breaker truck-operated auxiliary switch that is mounted on the stationary housing of a

removable circuit breaker.
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Appendix G

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COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

Main device parts

These letters denote parts of the main device, except auxiliary contacts, position switches, limit switches,

and torque limit switches.

BK Brake

C Coil/condenser/capacitor

CC Closing coil/closing contactor

HC Holding coil

M Operating motor

MF Fly-ball motor

ML Load-limit motor

MS Speed adjusting or synchronizing motor

OC Opening contactor

S Solenoid

SI Seal-in

T Target

TC Trip coil

V Valve

Other suffix letters

The following letters cover all other distinguishing features, characteristics, or conditions not specifically

described in Suggested Suffix Letters, which serve to describe the use of the device in the equipment,

such as

A Accelerating/automatic

B Blocking/backup

BF Breaker failure

C Close/cold

D Decelerating/detonate/down/disengaged

E Emergency/engaged

F Failure/forward

GP General purpose

H Hot/high

HIZ High impedance fault

HR Hand reset

HS High speed

L Left/local/low/lower/leading

M Manual

O Open/over

OFF Off

ON On

P Polarizing

R Right/raise/reclosing/receiving/remote/reverse

S Sending/swing

SHS Semi-high speed

T Test/trip/trailing
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Appendix G

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COPYRIGHT © 1996. IEEE. ALL RIGHTS RESERVED.

TDC Time-delay closing contact

TDDO Time delayed relay coil drop-out

TDO Time-delay opening contact

TDPU Time delayed relay coil pickup

THD Total harmonic distortion

U Up/under
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CHAPTER 13

INSTRUMENTS, TRANSDUCERS, AND METERS

13.1 INTRODUCTION

Substations employ many different systems to monitor operations. Depending on equipment types and

configurations, a large variety of instruments, transducers, and meters may be used to perform this

function.

13.2 INSTRUMENTS AND TRANSDUCERS

13.2.1 Definitions

An instrument is a device for sensing the magnitude of a physical quantity. It is calibrated or

programmed to indicate or record this magnitude based on a known standard. The instrument may be

indicating or recording. A transducer is a device that converts a physical quantity to a proportional lowlevel dc signal. Electrical transducers typically change amperes, watts, volts, and VARs to millivolt or

milliampere signals. Transducer outputs can be used to operate local instruments or can be employed in

data acquisition systems.

13.2.1.1 Indicating Instruments: An indicating instrument depicts the present value of the quantity

measured by the position of a pointer relative to a scale or as a digital display. It is used to give an

observer information regarding the present operation of equipment or circuits.

13.2.1.2 Recording (Graphic) Instruments: A recording or graphic instrument makes graphic

records of the value of a quantity as a function of time. This type of instrument is used when a permanent

record of how the measured quantity varies with time is needed.

13.2.2 Types of Instruments and Transducers

Instruments (indicating and recording) and transducers may be grouped according to the quantity they

measure. The specific quantity is generally used with the suffix “meter” to identify the instrument. Thus,

an ammeter is an instrument that measures amperes, a voltmeter is an instrument that measures voltages,

etc. The most commonly used instruments for measurements of electrical quantities are ammeter,

voltmeter, wattmeter, varmeter, frequency meter, and ohmmeter.

13.2.3 Classification of Instruments

13.2.3.1 Switchboard or Panel Instruments: Switchboard instruments are intended for fixed

installation on switchboards, panels, or consoles. Since they are constructed for fixed installations, they

require careful handling in transport. Panel instruments are similar to switchboard instruments, but are

used where smaller scale instruments are satisfactory.

13.2.4 Components of Instruments and Transducers

13.2.4.1 Analog Indicating Instruments: The components of analog indicating instruments are

mechanism, scale, base, and cover. The mechanism is an arrangement of parts for producing and controlling the motion of the indicating hand or pointer. The mechanism for electromagnetic instruments
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includes the moving element, magnetic structure, control spring, and instrument hand or pointer. The

components of thermal instruments are the same as those for electromagnetic instruments except the

mechanism consists of the moving element, bimetallic strip, heater, adjusting spring, and instrument hand

or pointer.

13.2.4.2 Digital Indicating Instruments: These instruments are completely solid state and either

contain a transducer or require inputs in the form of dc millivolt signals from transducers. The

instruments then condition the signals to eliminate noise bursts and surges, feed the conditioned signals to

analog to digital converters followed by binary-to-decimal encoders, and display the quantities on gaseous

discharge or light-emitting diode displays. Internal “clocks” (usually 1 kHz oscillators) update the

displays every millisecond. In addition to the digital display, these instruments may also have

communications circuitry to permit remote monitoring of the measured quantities.

13.2.4.3 Recording Instruments: These instruments are similar to digital indicating instruments but

have the additional capability of data storage. Recording instruments employ electronic memory to store

measured values recorded over a specified period. The stored data may be retrieved at a later date for

further review and study. Various forms of communication including telephone circuit, microwave radio,

and fiber-optic network may be used to retrieve data stored by the recording instrument. In some cases,

the recording instrument may be connected to a local printer. The local printer is used to produce a paper

copy of the stored data in table or graphical form.

13.2.5 Analog Instrument Scales

The instrument scale depicts the numerical value of the quantity being measured as indicated by the

position of the hand or pointer with respect to scale markings. Convenient scales will give more accurate

information and lessen observer eye strain. There are two basic types of instrument scales: linear scale

and nonlinear scale.

13.2.5.1 Linear Scale: This scale is divided into a number of equally spaced segments, each segment

representing the same unit of measurement. This type of scale is used when there are wide variations in

the magnitude of the measured quantity. Figure 13-1 shows two analog switchboard voltmeters with

linear scales.

Figure 13-1: Linear Scale Analog Switchboard Voltmeters. Courtesy of Yokogawa.
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13.2.5.2 Nonlinear Scale: This scale is divided into a number of unequally spaced segments. Each

segment may or may not represent the same unit of measurement. Usually the segments are expanded at

one end of the scale and compressed at the other end of the scale. This type of scale is used when

variations of the measured quantity are small and usually fall in the expanded area of the scale, thus

permitting more accurate readings. Figure 13-2 shows an analog switchboard power factor meter with a

nonlinear scale.

Figure 13-2: Nonlinear Scale Power Factor Meter. Courtesy of Yokogawa.

13.2.6 Operating Procedures

Instruments furnish valuable and indispensable information on the performance of an electric system or

device. Without this information, the operator would be almost completely uninformed and would have to

depend upon some crude or often inaccurate observations. Any abnormal indication should be

immediately investigated.

13.2.6.1 Reading Instrument Scales: The best instrument will serve no purpose unless properly read

and correctly interpreted. Good lighting is essential to accurate reading; glare as a result of reflection of

concentrated light should be avoided. Newer instruments have special covers to reduce glare. Some

instruments are direct reading in that the scales directly furnish the values of the measured quantities,

whereas other instruments require the use of instrument constants called scale factors. In this latter case

the actual measured quantity is obtained by multiplying the instrument indication as shown on the scale

by the scale factor. The scale factor may be shown on the instrument or may be associated with the

position of an instrument switch. In the latter case, each position of the instrument switch will represent a

different scale factor.

EXAMPLE 13-1: An ac ammeter with 0 to 5 ampere scale and 50 divisions has its indicating pointer

located on the 35 division point. The scale factor is 20 as shown on the ammeter switch. The measured

value is:

 20 70 Amperes

50

35 5

Scale Factor

Total Divisions

Instrument Reading Scale

= x =

x

x

x
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13.2.6.2 Care of Instruments: Instruments can withstand a certain amount of abuse such as

occasionally going off scale for momentary periods, but sustained overloads to the meter will damage the

mechanism or pointer. Instrument covers should be tightly fastened to the case to prevent entrance of

dust or fumes. Instruments should not be left for extended periods without covers.

13.2.6.2.1 Switchboard Instruments: These instruments are rather rugged devices, but should be

protected from excessive vibration and shock. The instruments should be kept clean to facilitate reading

of the measured quantity.

13.2.6.2.2 Recording Instruments: Recording instruments require additional care if they contain

printers or floppy disk drives. The instrument should be located in a dry place and kept clean. Printers

should be checked periodically to ensure they have a sufficient paper supply and are printing legibly.

Disks placed in disk drives should be monitored for sufficient storage space. It may be necessary to

replace the disk periodically, depending on the amount of information being stored.

13.3 METERS

13.3.1 Definition

An electric meter is a device that measures and registers the integral of an electrical quantity with respect

to time. The term “meter” is also used in a general sense to designate any type of measuring device

including all types of electrical measuring instruments. Use of “meter” as a suffix to a compound word

(e.g., voltmeter, ammeter, frequency meter) is universally accepted. However, in this chapter the narrow

meaning of “electric meter” is used.

13.3.2 Types of Electric Meters

The most common types of electric meters are watt-hour meter, VAR-hour meter, and ampere-hour

meter.

13.3.2.1 Watt-Hour Meter: The watt-hour meter is an electric meter that measures and registers

electric energy in watthours or kilowatt-hours (1,000 watt-hours).

EXAMPLE 13-2: If the active electric power of a circuit is 15 kW and is consumed at a uniform rate for

3 hours, the watt-hour meter will register 3 x 15 = 45 kWh.

13.3.2.2 VAR-Hour Meter: A VAR-hour meter is an electric meter that measures and registers

reactive power in reactive volt-ampere-hours (or reactive kilovolt-ampere-hours).

13.3.2.3 Ampere-Hour Meter: An ampere-hour meter is an electric meter that registers the quantity

of electricity in ampere-hours.

13.3.3 Demand Meter

A demand meter is a device that indicates or records the maximum average load over any specified time

interval (usually one hour or less) or the average load over a number of equal time intervals. It is a

special form of electric meter indicating or recording the measured load for a given time interval and then

resetting.
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13.3.4 Combination Watt-Hour and Demand Meters

These meters measure and register load and also indicate or record maximum demand.

EXAMPLE 13-3: If the active electric power in a circuit at the beginning of the measuring period is

20 kW and is uniformly decreasing until it reaches 10 kW at the end of 1 hour and then continues at the

same uniform rate of 10 kW for 2 more hours, the watt-hour meter will read 35 kWh at the end of the

third hour, and the demand meter will read a maximum 1-hour demand of 15 kW.

13.3.5 Types of Meter Indicating and Recording Devices

Each meter has a device that records the measured quantity. An electric meter usually has a register,

which registers the integrating load. The demand meter has an indicating, graphic (recording), printing,

or digital device. Digital device meters may also have communications circuitry to permit remote

monitoring of the measured quantities.

13.3.5.1 Electric Meter Registers and Register Constants: The registers are the prime concern of

the operators since the registers furnish the magnitude of electrical energy consumed by the load.

13.3.5.1.1 Register: The meter register may be dial (pointer) type or cyclometric (digital) type. In the

dial-type register, four or five dials are used to show the quantity measured. The register reads from left

to right with the highest reading on the four-dial register 9999 and on the five-dial register 99999. The

cyclometric register usually consists of four numbered rotating discs with the applicable number on each

disc visible through a slot on a plate in front of the register.

13.3.5.1.2 Register Constant: The register or dial constant of a meter is the multiplier used to convert

the register reading to the actual measured value. Its value may be 1, 10, or any multiple of 10. Another

constant, used with watt-hour meters, is the watt-hour constant, which is the registration of one revolution

of the meter disc expressed in watt-hours. This constant is used only when calibrating watt-hour meters,

but can be used to calculate the register constant. The register constant is usually marked on the meter

register, and the watt-hour constant is shown on the meter nameplate.

13.3.5.1.3 Electronic Register: Many modern electric meters have electronic registers. The electronic

register displays the quantity measured on a liquid crystal display (LCD) or other electronic screen.

Typically the units of the measured quantity are also displayed. No multiplier is required to convert the

displayed value to the actual measured value.

13.3.5.2 Indicating Demand Meter: This meter has a sweep hand to indicate the maximum demand

for any given period. This period might be 15, 30, or 60 minutes. The maximum demand indicating hand

is generally reset every month when the watt-hour meter reading is obtained.

13.3.5.3 Recording Demand Meter: This meter may be found in existing installations but is

generally not specified for new construction. The recording meter records the demand for each given

demand period on either a round or strip chart. This chart, therefore, indicates all the demands over a

given period. The maximum demand is determined by inspection of the meter chart.

13.3.5.4 Contact Device: This was originally a pair of contacts on a cam geared to the rotating disc

shaft of the watt-hour meter to produce a series of pulses. The pulse rate was directly proportional to the

speed at which the meter disc rotated. On more recent analog types, a second slotted disc geared to the
Bulletin 1724E-300

Page 656

meter shaft passes between a photocell and a light source. The resultant voltage pulse train produced is

amplified and applied to a reed relay to produce a contact pulse output.

13.3.5.5 Totalizer: This solid-state device receives pulse trains from several watt-hour meters and

produces a single output pulse train proportional to the sum of the inputs. Inputs may be additive or

subtractive.

13.3.5.6 Demand Meter Constant: The constant of a demand meter is the multiplier used to convert

the indicated or recorded demand reading on the meter to actual measured values. This constant may be

1, 10, or a multiple of 10. The demand meter constant and the register constant on the watt-hour meter do

not necessarily have the same value.

13.3.5.7 Digital Memory: Electronic meters typically have digital memory that will retain measured

values for a defined period. The values may be stored in random access memory (RAM) or on a magnetic

medium such as a tape drive, hard drive, or floppy disk. The values stored in digital memory can be read

by a computer connected to the digital memory device via local connection or through a communications

link.

13.3.6 Connection of Watt-Hour and VAR-Hour Meters

Watt-hour and VAR-hour meters have to have both current and potential connections to measure the

active and reactive energy. Watt-hour and VAR-hour meters are classified with respect to circuit

connections and the type of load being measured.

13.3.6.1 Self-Contained Watt-Hour and VAR-Hour Meters: The current and potential coils of

self-contained meters are connected directly to the circuit. These meters are normally used where the

circuit voltage does not exceed 240 volts and the continuous load does not exceed 30 amperes. Selfcontained watt-hour meters for 200- and even 400-ampere continuous load currents and 480 volts circuit

voltage are available but are usually only used in special cases.

13.3.6.2 Transformer-Type Meters: The current and potential coils of transformer-type meters are

connected to the circuit by means of current and potential transformers. These meters are normally used

when the circuit voltage exceeds 240 volts and/or the current is above 200 amperes. Current transformers

are used to reduce the current to the meter to 5 amperes at rated load. Potential transformers are used to

reduce the voltage to the meter to 120 volts.

13.3.6.3 Single-Phase Watt-Hour Meter: Both self-contained and transformer-type meters may be

used for single-phase systems. These meters have only one current and one potential coil. The

transformer-type meter is usually equipped with a small indicating lamp to show when the potential coil

is energized. This is important where the secondary of the potential transformer is fused.

13.3.6.4 Three-Phase, Two-Element Watt-Hour Meter: These meters have two current and two

potential coils and are used on three-phase, three-wire systems. Transformer-type meters require two

current transformers and two potential transformers. The meters often have two small indicating lamps to

show when the two potential coils of the watt-hour meter are energized.

13.3.6.5 Three-Phase, Two and a Half-Element Watt-Hour Meter: These meters have three

current coils and two potential coils and are used on three-phase, four-wire systems where the error due to

voltage unbalances on the three-phase system can be neglected. Transformer-type meters require three
Bulletin 1724E-300

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current transformers and two potential transformers. There are two potential indicating lamps to show

when the two potential coils are energized.

13.3.6.6 Three-Phase, Three-Element Watt-Hour Meter: These meters have three current coils

and three potential coils and are used on three-phase, four-wire systems where both current and voltage

unbalances can be expected. Transformer-type meters require three potential transformers and three

current transformers. There are three potential indicating lamps to show when the three potential coils are

energized.

13.4 MULTI-FUNCTION METERS

13.4.1 Definition

A multi-function meter is a combination device that performs the functions of instruments, transducers,

and meters. It is flexible, allowing the user to monitor many quantities simultaneously. It contains a

central processing unit (CPU) for the calculation and digital display of desired quantities. Most multifunction meters can be user configured to normally display a few quantities simultaneously while all

quantities can be read using push buttons on the front of the device or via remote monitoring. Many

multi-function meters also have digital memory for storing measured quantities recorded over a defined

period. Stored quantities can be downloaded to a laptop computer or other digital device. Figure 13-3

shows a multi-function meter.

Figure 13-3: Multi-Function Meter. Courtesy of Bitronics.
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13.4.2 Input Quantities

Multi-function meters require three voltage and three current inputs to monitor three-phase power circuits.

Because the multi-function meter is a microprocessor-based device, it can be set to calculate primary

voltage and primary current values based on inputs from potential and current transformers with a wide

range of primary-to-secondary ratios. The instrument transformer ratios are set at the factory but may be

changed in the field. Once the instrument transformer ratios are set, the meter will calculate and display

primary values with correct units. No scale factors are required to accurately read the meter display.

13.4.3 Measured and Calculated Values

Multi-function meters can measure and calculate many electrical quantities including instantaneous volts,

amps, watts, VARs, volt-amperes, power factor, and hertz. The meter may also record the instantaneous

maximum and minimum for each of these values over a pre-defined period. Accumulating quantities that

can be calculated include watt-hours and VAR-hours. The latest versions of multifunction meters are

incorporating programmable alarm levels and various power quality measurements. The meter can also

initiate communications to a remote master or PC when certain events or levels are measured.

13.4.4 Communications

Multi-function meters may communicate with remote terminal units (RTUs), programmable logic

controllers (PLCs), human–machine interfaces (HMIs), and other digital devices via local

communications network, common telephone lines, radio, or carrier signals coupled to power circuits.

Local network hardware typically conforms with either RS-232 or RS-485 standards. Additional

hardware and software requirements are defined by the communications protocol specified for the local

communications network. Telephone lines, radio, and carrier signals are often used by utilities for remote

meter reading. (See CRN’s Guide to Automatic Meter Reading: A Tutorial, Project 98-06.)

13.5 REFERENCES

ANSI Std. C12, “Code for Electricity Metering.”

ANSI Std. C39.1, “Requirements for Electrical Analog Indicating Instruments.”
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CHAPTER 14

SUBSTATION AUTOMATION

14.1 INTRODUCTION

Substation automation is the use of state-of-the-art computers, communications, and networking equipment

to optimize substation operations and to facilitate remote monitoring and control of substations costeffectively. Substation automation uses intelligent electronic devices in the substation to provide enhanced

integrated and coordinated monitoring and control capabilities. Substation automation may include traditional

SCADA equipment, but more often encompasses traditional SCADA functionality while providing extended

monitoring and control capabilities through the use of non-traditional system elements.

In the traditional SCADA system (legacy system), a host computer system (master station) located at the

energy control center communicates with remote terminal units located in the substations. RTUs are

traditionally “dumb” (non-intelligent) devices with very limited or no capability to perform local unsupervised

control. Control decisions are processed in the master station and then carried out by the RTU through the

use of discrete electromechanical control relays in the RTU. Analog telemetry information (watts, VARs,

volts, amps, etc.) is generated by discrete transducers whose outputs are wired into the RTU. Device status

(breaker position, load tap changer position, etc.) is monitored by the RTU through sensing of discrete

contacts on these devices. Monitored data is multiplexed by the RTU and communicated back to the master

station computer in the form of asynchronous serial data.

Substation automation systems do include many of the same basic elements as the legacy SCADA system but

with significant enhancements. A central operations computer system generally provides the master station

function. Legacy RTUs may be incorporated into the automation scheme, particularly in retrofit situations,

but are generally replaced with intelligent programmable RTUs and other IEDs in an integrated LAN. Legacy

transducers are replaced by IEDs that provide not only the traditional analog signals, but a number of

additional data values that can be useful to operations, engineering, and management personnel. IEDs

communicate with RTUs and local processors via a substation LAN with an open communications protocol,

thereby eliminating discrete transducer analog signals. Programmable logic controllers (PLCs) may be

included, discretely or integrated into the intelligent RTU, to provide closed loop control and control functions,

thereby eliminating the need for many electromechanical relays and interlocks.

The integration of IEDs in the substation has been a major challenge for electric utilities and

equipment suppliers. The primary obstacle has been the lack of standards for LAN

communications protocols, with manufacturers opting for proprietary protocols that require

costly interface modules for protocol conversion. Strides have been made in recent years to resolve

the protocol standardization problems, and some de facto standards have emerged. The trend will continue

toward more vendor-independent substation network environments as these standardization efforts move

forward and as the level of standards support improves among IED manufacturers. 

14.2 OPEN VS. PROPRIETARY SYSTEMS

All exchange of data among networked computers and devices may be thought of as part of a network

architecture, that is, a framework that provides the necessary physical and communications services to

facilitate data exchange. Any number of internally consistent architectures can be chosen to permit the

desired communications; however, many are proprietary. Proprietary networking solutions can prove to be
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highly effective and efficient from a functional standpoint, but they are not compatible with a multivendor

environment that many end users now demand.

In a proprietary network, the network vendor is in control of what features are supported within the network.

A vendor can decide not to support certain features, support them incompletely, or require the purchase of

expensive upgrades to implement those functions. But proprietary networks do have the advantage that the

user has access to a single point of contact and responsibility at the system vendor for all network functions,

and these networks are generally guaranteed to “plug and play” without the user having to be concerned about

architectures and protocols. A cautionary statement for proprietary systems is needed here. If or when the

vendor or his product becomes obsolete, ensure someone will handle support services for this network. An

escrow account for the source code of the system is a good starting point. This allows future modifications

to the system without having to re-engineer the entire system.

In a network based on open products and standards, the user is no longer dependent on a single vendor to

provide the functions and features needed or desired. The user also has the advantage of being able to solicit

competitive prices among equipment vendors rather than being locked into one source of supply. But in an

open environment, the user has to take responsibility for overall network functionality, and has to take care in

the selection of protocols and equipment to ensure “plug-and-play” compatibility.

Two widely accepted open system architectures are the International Organization for Standardization (ISO)

Open Systems Interconnection (OSI) 7-layer model, and the Transport Control Protocol/Internet Protocol

(TCP/IP) model. TCP/IP was originally developed for the ARPAnet, now called the Internet, but has been

widely used in local area networks. A more recent development is the Utility Communications Architecture

(UCA), which is a family of OSI-compliant protocols developed by EPRI for use in electric utilities. UCA is

discussed in greater detail in Section 14.4.6.2, Utility Communications Architecture.

14.3 SUBSTATION AUTOMATION ARCHITECTURE

The basic architecture of a utility automation system can be viewed as a multi-layered stack (Figure 14-1). At

the bottom of the stack are the electrical power substation field devices (transformers, breakers, switches,

etc.). The top of the stack is the user interface where data and control prerogatives are presented to the end

user, which in this case would be a human operator. The intermediate layers may be implemented with

discrete elements or subsystems. In some cases, several levels may be combined into one, or even eliminated

altogether.

The overall architecture can be viewed as two layers, each made up of several sublayers. The first or lowest

layer, the data acquisition and control layer, is made up of substation-resident equipment. The second or

highest layer, the utility enterprise, can be viewed as the information infrastructure layer. This bulletin

focuses on the substation-resident data acquisition and control layer.

14.4 DATA ACQUISITION AND CONTROL ELEMENTS

Substation automation may take many different forms and levels of sophistication, depending on the

philosophy of the implementing utility and the specific application. For instance, a single serial data interface

between a SCADA RTU and an electronic recloser would be an example of a relatively simple and limited

application. A fully automated substation with digital relays, electronic reclosers, and programmable logic

controllers, all sharing a common network with a substation host processor and man–machine interface,

would represent a relatively sophisticated application. Figure 14-2 shows the
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Figure 14-1: Substation Automation Architecture

major data acquisition and control elements found in substation automation and their typical relationship to

each other and to the corporate data infrastructure.

Regardless of the size and complexity of the network, the basic elements of substation automation are

generally those described in the following subsections.

14.4.1 Substation Host Processor

The substation host processor serves the following functions in the substation automation system: 

1. It provides local data storage for data acquired from the field devices.

2. It provides a local human–machine interface, allowing a human operator to locally access system

data, view system status, and issue system control commands.

3. It can, if necessary, perform logical data processing and closed-loop control algorithms.

4. It serves as a gateway for communications between the substation and the control center

(SCADA host).

The substation host processor may be a single computer, such as a PC, or multiple computers in a networked

or distributed computing environment. The substation host processor should be based upon
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Figure 14-2: Substation Automation Data Acquisition and Control Elements
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industry standards and have to have strong networking ability. A Windows-type graphical user interface

should be provided.

For smaller substations, a single non-redundant processor should suffice. For larger and more critical

substations, a dual-redundant processor with automatic failover is recommended. The level of redundancy

called for will vary by application, depending on what functions the host processor is providing, the level of

electromechanical backup employed, and the operational risks and implications related to an extended failure

of the processor.

14.4.2 Intelligent Electronic Devices

Examples of IEDs are electronic multifunction meters, digital relays, programmable logic controllers (PLCs),

digital fault recorders, sequence of events recorders, voltage regulators, capacitor bank controllers, and

electronic reclosers. Intelligent SCADA RTUs and PLCs can also be considered IEDs but are typically

categorized separately.

Many IEDs perform two functions within the substation. First, the IED provides its primary design function

such as relaying, capacitor control, or voltage regulation. But by virtue of the fact that many of these IEDs

have built-in instrument transformers, or are otherwise connected to the potential transformer (PT) and/or

current transformers (CT) circuits of the substation, the IEDs also calculate and provide a large amount of

power system data. 

Data available from IEDs includes but is not necessarily limited to the following information: 

1. Power flows (kilowatts, kilovars, power factor, phase angle, kilowatt-hours, kilovar-hours)

2. Other electrical data values (amperes, volts, symmetrical components)

3. Fault current (per phase, ground, waveform capture)

4. Relaying targets

5. Sequence of events

6. Oscilliography

Data is retrieved from the IED by the substation host processor and/or a local RTU digitally via a serial data

port or other network interface. This eliminates the need for discrete analog tranducers, accomplishing a

significant reduction in space and wiring, which can also lead to cost reductions, particularly on new (as

opposed to retrofitted) substations.

A single IED can often deliver hundreds of data values even though the utility user is only interested in a small

subset of the total data set. The ability to filter the data reported by the IED has been limited as a result of

both hardware and protocol-related issues. The goal is to provide the capability to filter or “mask” certain

data registers at the IED level, as opposed to making this function protocol or host-dependent. 

IEDs should be individually addressable, preventing the need for a dedicated communications channel for each

IED. IEDs should support open protocols such as DNP 3.0, ModBus, ASCII, UCA 2.0, IEC 870-5-101 or

103, or TCP/IP (see Section 14.4.6, Communication Protocols).

An important design consideration in development of IED interfaces is the data acquisition method. For

example, the IEDs may be polled by the host device for changes (report by exception), or the IEDs may be

sequentially scanned (full data dump). In the more common instance of a full scan, it is important to quantify

any limitations on the maximum allowable latency of the data (the time required for changes to appear in the
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host processor or data repository). These issues may play a role in the selection of IEDs and/or the

communication protocol and method.

14.4.3 Programmable Logic Controllers

PLCs may be considered IEDs, but are often considered as a separate class of device. Most IEDs are

designed to provide a primary function, such as reclosing, voltage regulation, relaying, or revenue metering,

while also offering ancillary system data that has some additional benefit to the utility. PLCs, on the other

hand, are more generic and can perform a wide variety of automation functions on a user-programmable

basis. 

PLCs have traditionally been used in industrial applications such as assembly line automation. PLCs have also

been widely used in power generating station distributed control systems, but have only recently been applied

in electric utility substations. One of the reasons for the lack of penetration by PLCs into the substation data

acquisition and control industry was that PLCs have only recently begun to be manufactured to rigorous

substation environmental and electrical standards, such as ANSI Std. C37.90a surge withstand capability. 

Another recent development is that, with the advent of faster microprocessors, PLCs can now perform

sophisticated control procedures fast enough to meet the requirements of substation protective relaying. 

PLCs are now finding applications in substations that were traditionally the realm of legacy SCADA RTUs.

PLCs can provide the same monitoring and supervisory control functions as an RTU. But PLCs offer the

advantages of lower costs than RTUs in some configurations, and ladder logic programmability not available

in the legacy RTUs. In an attempt to combat the influx of PLC products into their traditional markets, RTU

manufacturers have begun to offer lower cost RTUs with intelligent programmable features. The increased

intelligence and programmability of the RTU compared with the PLC’s same features should make the

defining border between the two obsolete.

In addition to providing traditional SCADA functions, PLCs are being used by utilities for a wide variety of

automation functions:

1. Reclosing

2. Auto-sectionalizing

3. Power line carrier automatic check-back schemes

4. Transformer LTC control

5. Capacitor controller

6. Local HMI for alarm annunciator, metering indication, data logging, and events recording

7. Breaker control, especially for more complex operations such as tie breakers

8. Breaker tripping for more complex schemes requiring a significant number of inputs

The programmability of PLCs lends to the development of schemes that were previously considered very

difficult to actuate. If the input can be obtained, the ladder logic to make decisions regarding the input can be

written to produce an output. Future additions to the substation may also be made simpler since the

substation wiring is made easier and logic may be readily changed with the use of PLCs.

Some utilities, because of the complexity of their control schemes, have used PLCs as a control device

between relays and breakers to provide tripping and closing of the breakers. While this is not generally

recommended, the use of PLCs minimizes installation time because of reduced wiring and control checkout

since the logic for any scheme may be entered into the ladder logic.
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14.4.4 Data Concentrator

Data concentrators are often the sole communications integration point within the substation. The data

concentration function is primarily the integration of multiple incompatible IED protocols for presentation to

an external host under a single unified protocol.

The role of the data concentrator is changing with the advent of UCA (see Section 14.4.6.2, Utility

Communications Architecture). UCA will allow for direct communications to all IEDs, regardless of whether

the communication is internal or external to the substation. But data concentrators may still be desirable for

bandwidth efficiency in low-bandwidth wide area telecommunications links.

14.4.5 Substation Local Area Network

The substation LAN provides a means of physical data transfer between intelligent devices in the substation.

There are two main distinctions between various LAN types: access method and physical media. The access

method, physical media, and transmission rate of the network in megabits per second (Mbps) will also dictate

the maximum distance between communicating devices (nodes).

14.4.5.1 Physical Media: The physical media used in LANs include coaxial cable, UTP (unshielded

twisted-pair) copper, and optical fiber. 

Optical fiber, because of its immunity to electrical effects, has distinct advantages in an electrical substation

environment. Coaxial cables and UTP can experience loss or corruption of data messages as a result of

electrical transients. Even though protocols at various layers can mitigate some of these adverse effects, it is

recommended that fiber-optic media be used to connect all IEDs engaged in protection functions.

14.4.5.2 Access Method: The access method can take various forms. The most common methods

are carrier sense multiple access with collision detection (CSMA/CD), token ring, and token bus, and the

Fiber Distributed Data Interface (FDDI), although a number of vendor-proprietary schemes are also in use. 

In selecting an access method, the designer has to consider the expected loading of the network, whether or

not a deterministic access method (see below) is required, desired data rate, and the physical distances

between nodes or communicating devices.

Networks that use CSMA/CD are generally referred to as Ethernet networks, although this is not always true.

 Ethernet is actually a proprietary access method developed by Digital Equipment Corporation, but was the

basis for the IEEE 802.3 networking standards. CSMA/CD is a broadcast access method where multiple

devices contend for access to the same communications medium in a bus architecture. It is a nondeterministic method, meaning that the amount of time required for a message to be sent and received cannot

be accurately determined, and is best applied in lightly loaded networks. Its non-deterministic behavior is a

disadvantage for time-critical automation tasks like closed-loop control. CSMA/CD is supported under

UCA 2.0.

Token ring (IEEE Std. 802.5) is the most commonly used token passing access method. Unlike CSMA/CD,

this method is deterministic because token passing among communicating devices is used to govern access to

the communications medium. Token ring is supported under UCA 2.0.

Token bus (IEEE Std. 802.4) is a bus access method like CSMA/CD, but uses a token passing arrangement

for deterministic medium access. Token bus, like token ring, is supported under UCA 2.0, but is less

commonly used than token ring or CSMA/CD.
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The Fiber Distributed Data Interface is described in ANSI Std. X3T12 and is supported within UCA. The

physical medium used is optical fiber, as opposed to coaxial cable UTP. Dual 100 Mbps fiber rings are

included, allowing for rerouting of data around a fiber fault. FDDI is primarily used as a backbone network

to connect multiple lower speed LANs in a large building or campus environment, so would be less commonly

used in a substation environment. Also, with the advent of 100 Mbps CSMA/CD, asynchronous transfer

mode switching and synchronous optical network technology, FDDI usage should wane in the coming years.

ATM is dedicated-connection switching technology that organizes digital data into packets and transmits them

using digital signal technology. Due to ATM’s ease in implementation by hardware, faster processing speeds

are possible. ATM runs on a layer on top of SONET. SONET is the U.S. (ANSI) standard for synchronous

data transmission on optical media. This standard ensures the interconnection between networks and that

existing conventional transmission systems can take advantage of optical media through tributary connections.

 Utilizing this technology can bring data speeds of 155.520 Mbps or 622.080 Mbps. Faster speeds are

expected in the near future. These two technologies are a major component of broadband ISDN (BISDN). 

FDDI usage should wane in the coming years because of this technology.

14.4.5.3 Serial Data Interfaces: Communications between intelligent devices in the substation may

take the form of synchronous or asynchronous serial connections rather than a LAN connection. Most RTU

vendors, for instance, offer serial ports on their RTUs for interfacing to IEDs with standard protocols. The

most common standard serial interfaces are RS-232, RS-422/423, and RS-485. Like LANs, these standards

define a physical and electrical interface and do not imply a particular protocol.

14.4.5.3.1 RS-232: The industry’s most common serial interface standard, RS-232 is defined by

ANSI/TIA/EIA Std. 232-E. It defines the interface between data communications equipment (DCE) and data

terminating equipment (DTE) employing serial binary data exchange. RS-232 signals are generally limited to

50 feet or less without the use of special low-capacitance conductors. 

14.4.5.3.2 RS-422/423: This standard serial interface is defined by ANSI/TIA/EIA Std. 422 that extends

the transmission speeds and distances beyond RS-232. It provides for a balanced voltage interface with a

high noise immunity. RS-423 is the unbalanced version. 

14.4.5.3.3 RS-485: This standard serial interface is defined by ANSI/TIA/EIA Std. 485. It provides for a

balanced voltage interface similar to RS-422, but uses tri-state drivers for multidrop or “daisy-chained”

applications. Because of its multidrop capability, this is the most common serial interface in substation data

communications.

14.4.6 Communication Protocols

14.4.6.1 General: For two devices to communicate successfully, not only they have to share a common

physical interface and access method (see Section 14.4.5, Substation LANs, and Section 14.4.5.3, Serial Data

Interfaces), but they have to also share a common protocol. A protocol is a formal set of conventions

governing the formatting and relative timing of message exchange between communicating systems. The

careful selection of communication protocols is essential for the successful deployment of substation

automation systems.

The prevalent approach among equipment manufacturers is to support several standard protocols. One RTU

vendor, for example, offers the end user a menu of 34 different protocols for the RTU-to-IED interface port,

and a single RTU can support up to 4 of these protocols simultaneously.
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Serious initiatives have been under way for several years among industry groups to address the issue of open

protocol development and standardization. These industry groups include the Institute of Electrical and

Electronics Engineers (IEEE) Power Engineering Society Substations Committee, EPRI, and the National

Rural Electric Cooperative Association (NRECA).

In 1994, the IEEE issued a trial use standard (IEEE Std. 1379) that recommended IEC 870-5 and DNP 3.0 as

alternative standards for master station-to-RTU and RTU-to-IED communications. DNP 3.0 has fostered the

widest support among vendors to date, making it somewhat of a de facto standard throughout the industry. 

Other protocols that have obtained wide support include ModBus, MMS, ASCII, and Landis & Gyr 8979.

The ISO-OSI 7- layer model is not described due to the complexity of the subject. The user is only exposed

to the application layer. For a detailed description, see CRN’s Enterprise-Wide Data Integration in a

Distribution Cooperative (Project 95-12).

14.4.6.1.1 Protocol Descriptions:

• IEC 870-5, developed by IEC Technical Committee 57 Working Group 3, answered the need for a

protocol standard for telecontrol, teleprotection, and associated telecommunications for electric

utility systems.

• DNP 3.0, developed by GE Harris Canada (at the time Westronic, Inc.), was established to

minimize the creation of new protocols used to communicate between SCADA devices. The

protocol is designed for data acquisition and application control in the electric utility field. This

protocol is maintained by the DNP Users Group.

• ModBus (ASCII and RTU) were developed by Modicon. These protocols define a message

structure that controllers are able to recognize and use; the protocol forms a common format for

the layout and contents of data messaging. 

• Manufacturing Message Specification (MMS) is an internationally standardized messaging system

for exchanging real-time data and supervisory control information between networked devices

and/or computer applications in a manner that is independent of the application function being

performed or the developer of the device or application. MMS is an international standard (ISO

9506) that is developed and maintained by Technical Committee Number 184 (TC 184), Industrial

Automation, of the International Organization for Standardization (ISO).

• Landis & Gyr 8979 is another standard byte-oriented protocol commonly used in the utility

marketplace.

A promising development in the effort to provide a universal open protocol standard is EPRI’s UCA, which is

described in Section 14.4.6.2. IEEE Std. 1379 was intended to be an intermediate standard to fill the gap until

the UCA standard was completed.

While there are “standard” protocols available, many of these are dynamic in that continuing development and

enhancements are taking place. Several versions of a particular protocol may exist in the marketplace. Two

devices that claim support of the same protocol may indeed support different versions or revisions of the

protocol, resulting in some lack of interoperability. To avoid such problems, it is incumbent on the design

engineer to research and understand the history of the selected protocol, whether multiple versions exist, and
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what continuing development, if any, is taking place. The designer should also be informed as to any

proprietary modifications to the standard protocol that may have been incorporated by potential equipment

suppliers as a means of optimizing its implementation with their devices.

The best way to avoid unforeseen protocol interoperability problems is to implement pre-engineered “plugand-play” interfaces. Equipment manufacturers should be required to demonstrate plug-and-play

interoperability between the specific devices in question, not just general compliance with a protocol, either

through factory testing or in actual field installations. If a new and untried interface is undertaken, the utility

should place the burden for protocol emulation and development on a single entity. This will typically be the

RTU manufacturer (in the case of RTU-to-IED interfaces) or the data concentrator manufacturer (in the case

of multiple protocol integration).

14.4.6.2 Utility Communications Architecture: EPRI developed UCA based on the ISO/OSI

standards for data communications. The overall goal of UCA is to provide interconnectivity and

interoperability between utility data communication systems for real-time information exchange. UCA

employs the Manufacturing Messaging Specification (MMS) to define the language, semantics, and services

for real-time data acquisition and control throughout general utility operations. Both the ISO/OSI and the

TCP/IP networking models are currently supported under UCA.

UCA Version 1.0 was adopted in 1991, providing a suite of selected protocols, with MMS as the

recommended protocol for real-time data acquisition and control applications. But UCA 1.0 lacked detailed

specifications of how the protocols would actually be used in field devices. UCA Version 2.0 addresses this

problem.

The development of UCA Version 2.0 at the substation level was facilitated by EPRI Project RP-3599,

“Integrated Protection, Control and Data Acquisition,” in which numerous utilities and manufacturers

participated, with American Electric Power (AEP) as the lead participant. This work has generally been

completed for power system devices with the issuance of UCA 2.0 General Object Models for Substation and

Feeder Field Devices, Draft Version 0.7, December 1997 (GOMSFE). The effort of the document is to

merge the substation and feeder automation work with that of UCA version 2.0 in order to produce common

generic object models for implementation of UCA 2.0-compliant field devices in electric utilities.

Work on UCA Version 2.0 continued in 1998 with the EPRI/AEP Utility Substation Communications Initiative

Project. A continuation of EPRI Project RP-3599, this project’s goal is to evaluate and recommend a UCAcompliant substation LAN and to demonstrate IED interoperability. This project includes implementation at 13

demonstration sites in the United States and Germany, with targeted completion in 1999.

Work on the UCA standards should continue over the next few years. A new IEEE subcommittee, SCC 36,

will oversee its further development.
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14.5 REFERENCES

ANSI Std. C37.1, “Definition, Specification & Analysis of Systems Used for Supervisory Control, Data

Acquisition & Automatic Control.”

ANSI Std. C37.90a, “Electrical Characteristics of Surge Protectors for Use in Programmable Logic.”

ANSI Std. X3T12, “Physical Media Dependent, Physical Media Access Control and Station Management

Specifications for Optical Fiber Based Token-Ring Network.”

ANSI/IEEE Std. 802.3, “Information Technology- Telecommunications and Information Exchange Between

Systems- Local and Metropolitan Area Networks – Specific Requirements – Part 3: Carrier Sense

Multiple Access with Collision Detection (CSMA/CD) Access Method and Physical Layer

Specifications.”

ANSI/IEEE Std. 802.3v, “Information Technology – Local and Metropolitan Area Networks – Part 3: Carrier

Sense Multiple Access with Collision Detection (CSMA/CD) Access Method and Physical Layer

Specifications, Informative Annex for Support of 150 ohm Cables in 10 BASE-T Link Segment.”

ANSI/TIA/EIA Std. 310–D, “Racks, Panels, and Associated Equipment.”

ANSI/TIA/EIA Std. 232-E, “Interface Between Data Terminal Equipment and Data Circuit-Terminating

Equipment Employing Serial Binary Data Interchange.”

ANSI/TIA/EIA Std. 422, “Electrical Characteristics of Balanced Voltage Digital Interface Circuits.”

ANSI/TIA/EIA Std. 423, “Electrical Characteristics of Unbalanced Voltage Digital Interface Circuits.”

ANSI/TIA/EIA Std. 485, “Electrical Characteristics of Generators and Receivers for use in Balanced Digital

Multipoint Systems.”

ANSI/TIA/EIA Std. 568-A, “Commercial Building Telecommunication Wiring Standard.”

BELLCORE/GR-1230-CORE, “SONET Bi-directional Line-Switched Ring Equipment Generic Criteria.”

BELLCORE/GR-1400-CORE, “SONET Dual Fed Unidirectional Path Switch Ring (UPSR) Equipment Generic

Criteria.”

BELLCORE/GR-253-CORE, “Synchronous Optical Network (SONET) Transport Systems: Common Generic

Criteria.”

BELLCORE/RECMN V.35, “Data Transmission Using 60-108 kHz Group Band Circuits- Data

Communication Over the Telephone Network.”

BELLCORE/TR-TSY-000191, “Alarm Indication Signals Requirements and Objective Controllers.”

EPRI Project RP-3599, “Integrated Protection, Control and Data Acquisition.”
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EPRI/UCA 2.0 GOMSFE, “General Object Models for Substation and Feeder Field Devices,” Draft

Version 0.7, December 1997.

IEC 870-5-101, Telecontrol Equipment and Systems, Part 5: Transmission Protocols- Section 101:

“Companion Standard for Basic Telecontrol Tasks, First Edition.”

IEC 870-5-103, Telecontrol Equipment and Systems, Part 5: Transmission Protocols- Section 103:

“Companion Standard for the Informative Interface of Protection Equipment.”

IEEE Std. 802.4, “Token Passing Bus Access Method and Physical Layer Specifications.”

IEEE Std. 802.5, “Information Processing Systems – Local and Metropolitan Area Networks – Part 5: Token

Ring Access Method and Physical Layer Specifications.”

IEEE Std. 1379, “IEEE Trial Use Recommended Practice for Data Communications Between Intelligent

Electronic Devices and Remote Terminal Units in a Substation.”

RS-232, “Interface Between Data Terminal Equipment and Data Circuit-Terminating Equipment Employing

Serial Binary Data Interchange.”

RS-422, “Electrical Characteristics of Balanced Voltage Digital Interface Circuits.”

RS-423, “Electrical Characteristics of Unbalanced Voltage Digital Interface Circuits.”

RS-485, “Serial Balanced Voltage Interface Using Tri-State Drivers for Multidrop Applications.”
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APPENDIX H TO CHAPTER 14

GLOSSARY OF TERMS

Asynchronous Transfer Mode (ATM): A communications transmission and switching standard for

carrying broadband signals at speeds up to 2.2 gigabits per second. Combines techniques of time division

multiplexing and packet switching.

Carrier Sense Multiple Access with Collision Detection (CSMA/CD): A LAN contention-based

access-control protocol technique (Ethernet); defined in IEEE Std. 802.3.

Data Circuit-Terminating Equipment (DCE): Formerly known as data communications equipment;

network-embedded devices that provide an attachment point for user devices.

Data Terminal Equipment (DTE): The computing instrument, apart from any device used to perform the

analog transmission and reception of data; examples are computers, RTUs, and PLCs.

Fiber Distributed Data Interface (FDDI): Shared-medium, ring topology LAN that operates at 100

Mbps. It is ANSI Std. X3T9.5, using fiber-optic cable as the medium.

HMI: Human–machine interface.

Intelligent Electronic Device (IED): Electronic equipment that provides monitoring and controlling

capabilities.

Ladder Logic: Industry-standard symbology used to document relay logic control systems. Logic lines are

drawn horizontally, similar to the rungs of a ladder.

Legacy: Existing implementation of an application or project; it does not refer to trials.

Local Area Network (LAN): A group of computers connected over a common medium within a building.

Master Station: The “central host” computer in a SCADA system.

Open Systems Interconnection (OSI): An international standard describing seven layers of

communication protocols (physical, data link, network, transport, session, presentation, and application) that

allow many dissimilar information systems including computers, workstations, PBXs, etc. to be

interconnected.

Programmable Logic Controller (PLC): Electronic device that can be programmed using a specific

language via a computer.

Remote Terminal Unit (RTU): An electronic device used to control and monitor Input/Output points

within an overall system and to communicate the derived data to a master station or other “host” unit.

SCADA: Supervisory Control and Data Acquisition; used by utilities and other process-oriented operations

to collect data from machinery that may be located over a widespread area. A basic SCADA system consists
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of two types of devices: “master” and “remote.” The master resides at a centrally manned location while the

remotes are generally placed at unmanned locations. Communication between master and a number of

remotes can be via telephone-like circuits, radio channels, or fiber-optic communications media.

SONET: Synchronous Optical Network; standard for optical transport formulated by the Exchange Carrier

Standards Association ( ESCA) for ANSI; essentially a standard for Broadband Integrated Services Digital

Network transmission facilities.

Token Bus: A networking standard that uses a bus configuration and a broadcast messaging system. 

Token bus networks use a token-passing scheme to determine which node has the network access.

Token Ring: A LAN that uses the token-passing access method and that supports 4 Mbps or 16 Mbps

baseband communications in a physical star and logical ring arrangement.

Transport Control Protocol/Internet Protocol (TCP/IP): The main transport protocol used on the

Internet for connectivity and transmission of data across heterogeneous systems. It is an open standard that

is available on most UNIX systems, VMS and other minicomputer systems, many mainframe and

supercomputing systems, and some microcomputer and PC systems.

Utility Communications Architecture (UCA): Developed by EPRI based on the ISO/OSI Standards for

data communications.

UTP: Unshielded Twisted Pair.

Wide Area Network (WAN): A computer network interconnected over distances beyond a city or

metropolitan area.
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CHAPTER 15

AC AND DC AUXILIARY SYSTEMS

15.1 AC AUXILIARY SYSTEM

15.1.1 Typical Loads Supplied

Substation ac auxiliary systems are typically used to supply loads such as:

1. Transformer cooling, oil pumps, and load tap changers

2. Circuit breaker air compressors and charging motors

3. Outdoor device heaters

4. Outdoor lighting and receptacles

5. Control house

a. Lighting and receptacles

b. Heating, ventilating, and air conditioning

c. Battery charger input

d. Water well pump

6. Motor-operated disconnecting switches

15.1.2 Design Requirements

15.1.2.1 Demand Load: Tabulate the connected kVA of all substation ac loads and apply a demand

factor to each. Demand kVA is used to size the auxiliary transformer(s). Load diversity and load factor

need not be considered in this case.

In auxiliary transformer sizing, examine the substation growth rate. If expansion is planned in the near

future, consider the estimated demand load of the expansion in the transformer size. If expansion is in the

far future, it may be economically advantageous to plan for the addition of a transformer at expansion

time.

15.1.2.2 Number of Primary Feeds: In small distribution substations one auxiliary transformer is

usually sufficient.

As substation size increases, customer load criticality increases. A decision has to be made as to

redundancy of substation auxiliary services in light of economics and customer requirements. Large

transmission substations, servicing large load blocks, and distribution stations, should have dual feeders

serving two separate auxiliary transformers.

When dual feeds are selected, locate two separate, independent sources so the loss of one will not affect

service of the other. Designate the least reliable as the alternative supply. A popular option to consider in

this case is the use of a tertiary winding of the power transformer as a normal source.

An alternative source could be a distribution feeder at a customer service level, 480 or 240 volts, single or

three phase. Depending on auxiliary secondary voltage level selected, this could eliminate one

transformer.
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15.1.2.3 Overhead or Underground Entry: The auxiliary source(s) could be either overhead or

underground distribution lines. When undergrounding within the substation property, even from an

overhead source, direct-buried conduit is recommended. A spare, capped, conduit should be installed to

minimize down time if a cable failure occurs. The faulted cable can always be removed after service

restoration.

15.1.2.4 Critical Loads: Some low-voltage loads have to be maintained at all times:

1. Battery chargers which, through the batteries, supply breaker trip and close circuits as well as

communication circuits

2. Transformer cooling

3. Power circuit breaker compressors and motors

4. Trouble light receptacles in the station yard

5. Security lighting

6. Breaker control circuits

7. Fire alarm circuit(s)

8. Electric heating

9. Substation automation circuitry

Critical loads for each station should be determined. These loads should be served from a panel(s) fed

from the normal source and representing the minimum load for transfer to alternative supply.

15.1.2.5 Secondary Voltage Level: Several secondary voltage or utilization levels are available for

ac auxiliaries. For the purposes of standardization, on a given power system it is best that only one level

be selected. This is not a limiting rule, however. An exception could be justified.

Possible secondary voltage levels as illustrated in Figure 15-1 are as follows:

1. 480/240 Volts, Three-Phase Delta

Three-phase transformer fans and oil pumps need to be specified at 480 volts. In practice, the units

are rated at 460/230 volts, but this is inside the NEMA plus 10 percent voltage requirement.

Other loads may be specified at either 480 or 240 volts, single phase.

This system is ungrounded and should be used with a ground detection system so that a “fault” or

one leg of the system will cause an alarm. The system should trip when a second leg on the system

is grounded.

2. 480/277 Volts, Wye Connected, Three-Phase, Four-Wire

Three-phase transformer fans and oil pumps need to be specified at 480 volts. In practice, the

motors are rated 460/230 volts, but this is within the NEMA plus 10 percent voltage requirement.

The advantage here is that luminaires can be equipped with 277-volt ballasts, saving lighting

transformer costs over use of more common 120-volt lamped luminaires. Convenience receptacles

are fed through small dry-type 480-120 volt transformers.
Bulletin 1724E-300

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Figure 15-1: Typical AC Auxiliary System Secondary Voltages
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3. 208/120 Volts, Wye-Connected, Three-Phase, Four-Wire

Three-phase 208 volts or single-phase 120 volts or a combination of the two can be used for

transformer cooling. Combination power and lighting panels can be used, resulting in reduced

labor and material costs. This saving could be offset by higher conductor costs as compared to the

480-volt system. Receptacles can be served with 120 volts directly.

4. 240 Volts, Three-Phase Delta

Three-phase transformer fans and oil pumps need to be specified at 240 volts. In practice, the

motors are rated at 230 volts, but this is inside the NEMA plus 10 percent voltage requirements.

This system is ungrounded and should be used with a ground detection system so that a “fault” on

one leg of the system will cause an alarm. The system should trip when a second leg on the system

is grounded.

5. 240/120 Volts, Delta-Connected, Three-Phase, Four-Wire

This is the most common level in use in moderate-size substations. One phase of the auxiliary

transformer is center tapped to obtain 120 volts. Combination panels can be used, and 240-volt

single-phase loads can be served.

6. 240/120 Volts, Open Delta-Connected, Three-Phase, Four-Wire

This is essentially the same as the closed delta connection except only 58 percent of the kVA

capacity of the three transformers can be used. This configuration will provide construction

economy for a medium-size installation or for temporary use. With single-phase units, the third

transformer can be added in the future for increased kVA capacity. It is frequently used for

construction power where both three-phase and single-phase supplies are required.

7. 240/120 Volts, Single-Phase, Three-Wire

This is “residential” service but applicable to small substations. Common panels can be used, with

two available voltages.

15.1.2.6 Transfer Scheme: Where two sources, normal and alternative, are feeding substation

auxiliaries, a means to transfer from one to the other has to be established. At an attended station this can

be a manual transfer arrangement. Automatic transfer has to be provided at an unattended station.

Transfer is done on the secondary side for equipment economy. Article 700 of the National Electrical

Code (NEC) outlines general requirements for this type of scheme. A typical configuration is shown in

Figure 15-2.

Transfer switch selection is an important factor in the system design. Operation should be “break before

make” double-throw operation to prevent shorting the two sources. Mechanical interlocking should be

provided to ensure the switch can be in only one of the two positions. The switch should have an ampere

withstand capability for faults at points A, B, and C of Figure 15-2. The fault at C will be highest, the

feeder impedance to B and A limiting the fault current to an amount below that at C.

The auxiliary system in Figure 15-2 assumes transfer of all loads. The full load current of the 150 kVA

transformer is 360 amperes, so a 400-ampere switch would be selected.
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Figure 15-2: Typical AC Auxiliary System

Assuming a 250,000 kVA source, two 500 kcmil, 3.05-meter (10-foot) feeders per phase to the switch,

and 4 percent transformer reactance, the fault current is approximately 10,000 amperes. This value is

well within manufacturers’ standard ratings for 400-ampere full load transfer switches.

Automatic transfer switches are built to detect emergency conditions and transfer to the alternative supply

when the normal supply falls to 83 percent of rated voltage. Return to normal supply is accomplished

through an adjustable time delay at approximately 92 to 95 percent of rated voltage. A variety of accessories are available with transfer switches. Manufacturers’ data is readily available, and the engineer

should consult such data when specifying a transfer switch. Provide means to alarm for loss of voltage

from either source.

15.1.2.7 Auxiliary System Fault Currents: The determination of fault currents in three-phase ac

auxiliary systems is just as basic as the determination of load currents in sizing circuit breakers or fuses.
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3 * OhmsReactance

Line - to - Line kV IF =

The protective device has to operate or open during faults as well as carry load current during normal

conditions or equipment damage could result.

The symmetrical short circuit (fault) current is computed using Equation 15-1:

Equation 15-1

Ohms reactance is the total reactance of all current-carrying parts from the source to the fault.

In Figure 15-2 the 250,000 kVA source has a reactance of 0.00023 ohms. The 150 kVA transformer

reactance is 0.0023 ohms, the current transformer 0.0005 ohms, the 3.05-meter (10-foot) cable about

0.001 ohms, and so forth. All reactances are totaled and used in Equation 15-1. The asymmetrical fault

current is a function of the fault circuit X/R ratio. A multiplying factor (1.7) for the asymmetrical current

is satisfactory for auxiliary power system calculations.

Fuse and circuit breaker manufacturers have handbooks with X, R, and Z values for transformers, current

transformers, cables, etc., together with methods for determining protective device ratings based on estimated fault currents.

15.1.3 Equipment

15.1.3.1 Transformers: ANSI Std. C57.12.25, “Pad-Mounted Compartmental-Type, Self-Cooled,

Single-Phase Distribution Transformers with Separable Insulated High-Voltage Connectors; High

Voltage, 34500 GRD Y/19920 Volts and Below; Low Voltage, 240/120 Volts; 167 kVA and Smaller—

Requirements,” and ANSI Std. C57.12.26, “Pad-Mounted Compartmental-Type Self-Cooled, ThreePhase Distribution Transformers for Use with Separable Insulated High-Voltage Connectors, High

Voltage, 34500 GRD Y/19920 Volts and Below; 2500 kVA and Smaller,” are applicable for selection of

ac auxiliary system pad-mounted transformers. This type of transformer is good for large substation

auxiliary service use. The increasing use of underground distribution has made these units readily

available from major manufacturers. Pad mounts meeting RUS specifications and with RUS accessory

packages are catalog items.

The secondary voltage levels listed in Section 15.1.2.5 are manufacturers’ standards.

Consider the feasibility of establishing substation auxiliary system voltage at the same level as that for

serving underground customers. With this standardization, spare transformers can be stocked and both

customer and substation service maintained at minimum cost.

Pad-mounted transformers can be purchased with fused switches on the primary side for transformer fault

current protection. High-voltage fuses, in this use sized for full-load transformer primary currents, will

inherently have sufficient current interrupting ratings to protect the transformers under fault conditions.

Primary load break switches are also available.

If the normal and alternative sources are overhead, pole-mounted, and hook stick operated, fused switches

are a possible solution to transformer primary protection. Underground cable is used for the connection

from the switches to the transformer pad. Cable for this application is discussed in Chapter 10.
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Pad-mounted transformers and the kVA ratings previously mentioned apply to a fairly large substation.

For smaller installations, structure-mounted distribution transformers, properly applied, can be used.

15.1.3.2 Electrical Panelboards: The definition of a branch circuit panelboard in the NEC

(Article 384) is one having more than 10 percent of its overcurrent devices rated 30 amperes or less for

which neutral connections are provided. Additionally, the number of branch circuit devices in one

enclosure is limited to 42 poles.

Switchboards differ from panelboards in that switchboards are free standing. Front or rear access to line

and load terminals are vendor options. Branches can be group mounted or individually mounted, with or

without barriers.

Enclosures should be specified NEMA 1, general service for indoor use, or NEMA 3R, raintight for

outdoor use.

Panelboards are available for flush or surface mounting, with fusible or circuit breaker branch circuits.

Main breakers, if required, can be furnished. Voltage ratings for any level selected from Section 15.1.2.5

can be supplied.

The main decision to be made in panelboard selection is whether to use fusible or circuit breaker

branches. The branch circuit device is used to protect the branch circuit wiring, so the decision should be

based on first cost and maintainability. For a very small installation with few circuits, fuses will mean

lower first cost.

If fuses are selected, an inventory has to be maintained at the substation. There is always the possibility,

however remote, that the wrong size could be used as replacement for a blown fuse. These problems do

not exist with circuit breakers, a plus factor relative to maintainability.

For lighting circuit service exclusively, in a moderately sized installation, a circuit breaker panelboard

offers the advantage of switching the lights, thereby eliminating light switches. For exterior lighting, the

engineer may consider mounting a weatherproof three-pole magnetic contactor fed from an adjacent

outdoor panel.

15.1.3.3 Lighting and Heating Equipment: Outdoor lighting serves two basic purposes: substation

security and safety. Depending on the area, certain luminaires may be used during hours of darkness for

substation security. These are photoelectrically controlled. A microwave tower could require FAA

lighting. This would also be controlled photoelectrically.

Lamps for outdoor use are essentially incandescent, mercury, or sodium lamps. Except for an unusual

condition, the lamps presently in use on a given system should continue in use, simplifying inventory.

The unusual condition could be a new large substation where a different source is desirable and a

separate, on-station inventory can be kept.

Luminaires for substation use, from the basic flat dome reflector to Illuminating Engineering Society

(IES) pattern refractors, are available. Pole-top or bracket mountings can be used. The engineer, with the

proper vendor data, can develop a lighting layout to satisfy the purpose required. Yard lighting design is

beyond the scope of this guide. The basic requirements are one or two foot-candles in equipment areas.

Convenience receptacles should be in equipment cabinets and also strategically located to serve 50-foot

extension cords with trouble lights. Convenience receptacles in the substation yard should have ground

fault interruption protection.
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Indoor lighting should be designed for maximum operator convenience. Luminaires should be located to

adequately illuminate relay and control panel fronts. With fluorescent units, 4-foot lamps are

recommended, since storage is easier than for 8-foot lamps. Provide duplex receptacles for extension

cord lights for initial panel interconnection work, relay setting, and plant maintenance.

Provide control house electric heating for comfort and freeze prevention. This can be done with ceiling or

wall-mounted electric unit heaters and/or electric baseboard heating units. Provide powered roof

ventilator(s) along with floor-level, manually operated wall louver(s) to provide for three to five air

changes per hour. Louvers should be provided with fusible links as a means, in case of fire, to keep

damage to a minimum. Gravity roof ventilators should always be installed to prevent concentration of

hydrogen in battery rooms.

Air conditioning of the control house, where required, is best provided by packaged through-wall unit(s).

Packaged through-wall units pump an energy-efficient heating/cooling option for most climates and can

have supplemental resistance heat. Built-in resistance heaters are provided in some to provide all-season

use. Vendor data is available as an aid in selecting such units.

15.1.4 Summary

A substation ac auxiliary system consists mainly of the following parts:

a. One or two incoming primary feed(s) seldom above the 34.5 kV level, one designated normal

source, the other designated alternative source. The sources should be as independent as

possible.

b. One or two auxiliary transformers to reduce the primary voltage to the utilization level.

c. A main switchboard, usually located outdoors between the two transformers. This

switchboard houses the transfer switch and fuses or circuit breakers to feed both control house

and yard panelboards.

Panelboards (indoor or outdoor) having circuit breakers or fuses sized for the loads involved should have

approximately 20 percent spare breakers or fuses.

All branch circuit breakers feeding ac yard circuits shall be Ground Fault Interrupting type (GFI). Where

fused panels are selected, yard receptacles shall be GFI type.

15.2 DC AUXILIARY SYSTEM

15.2.1 Typical Loads Supplied

Substation dc auxiliary systems are typically used to supply loads consisting of the following:

a. Relaying, supervisory, alarm, and control equipment

b. Emergency control house lighting

c. Circuit breaker trip and close circuits
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15.2.2 Design Requirements

A substation dc system consists of a battery of suitable voltage (number of cells) and suitable size

(ampere-hour capacity) connected in parallel with a control bus together with properly selected voltageregulated charging equipment.

At a single location where two distinct dc voltages are required, i.e., possibly 48 volts for microwave and

120 volts for substation operation, two separate batteries and chargers is one option. Tapping a larger unit

to obtain the smaller voltage is not recommended. Another option to obtain different dc voltages is a dcto-dc converter. This is usually used for small loads and is available from the manufacturer.

The charging equipment consists of a full wave rectifier with regulated output voltage. Normally, the

charger operates continuously to furnish direct current to the control bus for steady loads such as

indicating lamps, holding coils, and relays, plus a small current to maintain the battery at full charge.

Intermittent loads of short duration such as tripping or closing of circuit breakers or automatic operation

of other equipment are handled by the charger within the limits of its capacity. Any excess load is

supplied by the battery, which is automatically recharged when the intermittent load ceases. Should the

ac input to the charger fail, the battery carries the entire load.

The control bus may be a dc bus in a switchgear assembly or, in the case of a large substation, a dc or

group of dc panels.

DC voltage requirements for solid-state relaying, event recorders, data acquisition, and other such devices

are generally below the voltage levels for circuit breaker trip coils. Actual requirements vary with

different vendors. Some types of equipment are provided with individual rectifiers, rack mounted,

changing 120 volts, 60 hertz ac, to 12, 24, or 48 volts dc. If the ac supply fails, static switching changes

the source to the main dc batteries and required dc converter. An alarm indication is provided to indicate

this status. Other equipment is designed to be fed directly from the main batteries with ac/dc converters

to supply the static device voltage.

Two of the most important components of a substation dc system are the main battery and charger. These

components should be sized correctly. Undersizing could possibly mean a circuit breaker reclose failure

and undue service interruption. Oversizing, while not damaging, is expensive. However, the cost of the

supply is a fraction of total substation cost, and the economics should be balanced with reliability. At a

minimum, the main battery should be sized to allow normal substation operation for 8 hours.

15.2.3 Types of Cells

Before determining the cell ampere-hour rating, the type of cell for the particular application has to be

selected. There is no need for cell standardization on a power system. Once a battery is installed for

stationary service, it stays in place for up to 30 years. Interchangeability on the system is unnecessary.

The types of secondary cells readily available today are:

1. Lead acid

2. Nickle cadmium (NI-CAD)

3. Lead calcium

A brief description of the three predominant types follows. For theory and history too lengthy to be

considered here, see Batteries and Energy Systems by Dr. C.L. Mantell.
Bulletin 1724E-300

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In the case where no standards are established, select battery type based on:

1. First cost

2. Years of float life

3. Annual depreciation

4. Number of deep discharges required over the life of the battery

15.2.3.1 Lead Acid Cell: This cell has a positive plate of lead peroxide and a negative plate of pure

sponge lead. The electrolyte is dilute sulphuric acid. Open circuit voltage of a fully charged cell is a

nominal 2.25 volts; voltage varies depending on electrolyte strength and cell temperature.

Battery condition can be determined with a hydrometer using Equation 15-2:

Equation 15-2

Where:

S. G. = Specific gravity of the electrolyte

The specific gravity of the electrolyte varies with cell temperature, so a thermometer should be a part of

the maintenance kit. The higher the temperature, the lower the specific gravity. Battery ratings are

usually specified at 25oC (77oF). Temperature correction curves are included with the battery

manufacturer’s instruction manual, as are charge and discharge curves.

15.2.3.2 Nickel Cadmium: This cell has a positive plate of nickel hydrate and a negative plate of

cadmium sponge. The electrolyte is a solution of potassium hydroxide with a specific gravity from 1.160

to 1.190 at 25oC (77oF). Open-circuit voltage may vary from 1.30 to 1.38 volts. The cell voltage is

1.4 volts fully charged at 25oC (77oF). The specific gravity of the electrolyte is constant regardless of

charge state.

The nickel cadmium battery has the advantages of infrequent maintenance requirements, absence of

corrosive fumes, immunity to inadvertent overcharge, and the reduced derating required for ambient

temperatures below 25oC (77oF). The absence of corrosive sulphuric acid fumes allows the installation of

“NI-CADS” in cubicles, a possible advantage in some installations. The primary reason for the lack of

greater use of NI-CADS for main substation batteries is initial cost.

15.2.3.3 Lead Calcium: This cell is similar to the lead acid type with the exception of the addition of

approximately 0.8 percent calcium to the lead grid for additional strength. This alloy also greatly reduces

cell internal losses.

15.2.4 Typical Loads and Duty Cycle

To accurately specify a battery and associated charger, the dc load has to be accurately defined. Each

single item of equipment connected to the dc system has to be individually tabulated with the following

pertinent data included:

• Voltage

• Current requirement

• Duration of operation

Cell Volts = S. G. + 0.84
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• Frequency of use

The last two items constitute the duty cycle.

DC voltages of 24, 32, 48, 120, and 240 are normally encountered in substation design. For the purpose

of this guide, a 120-volt battery with a nominal voltage per cell of 2 volts and 60 cells will be considered.

A final voltage of 1.75 per cell or 105 volts for the battery will complete our model.

DC system loads consist of both continuous and intermittent loads. Continuous load typically involves

the battery 3- to 8-hour ratings. It consists of indicating lights, relays, and any other equipment

continually drawing current from the dc bus. Emergency lighting consisting of circuits energized during

an ac outage plus certain communication circuits involving the 1- to 3-hour rating.

Intermittent or momentary load, constituting relay and breaker operation, involves the 1-minute battery

rating. The duration of breaker operation may be only a few cycles, but the battery voltage drop will be

essentially the same after 1 minute. A typical duty cycle will have the breakers tripping at the beginning

of the cycle and closing at the end of the cycle. If two or more breakers are to operate simultaneously, the

total current determines the 1-minute rating.

The sizing of dc cables and cabinets is done in the same way as for ac services. The only exception is that

no demand factor should be applied to connected loads. Voltage drop should be held to within 3 percent.

Special consideration of short-circuit capacity is not a factor in a dc auxiliary system.

Figure 15-3 illustrates a typical dc system for substation auxiliary services.

15.2.5 Equipment

15.2.5.1 Battery Selection: Lead batteries are rated in ampere-hour capacity at an 8-hour rate to

1.75 volts average at 25oC (77oF).

EXAMPLE 15-1: Battery Selection

The model duty cycle could be:

Ten 40-watt, 120-volt lamps - 3 hrs. 3.5 amperes

Relays and panel indicating lamps - 8 hrs. 5.0 amperes

Communications - 3 hrs. 5.0 amperes

Three simultaneous Breaker Operations - 1 min. 100.0 amperes

From vendor data a cell of seven plates will furnish approximately 200 amperes for 1 minute to 1.75

final volts. The ampere-hour capacity of the selected unit at the 8-, 5-, 3-, and 1-hour rates is about 145,

130, 115, and 80, respectively.
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Figure 15-3: Typical DC Auxiliary System
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This model duty cycle is only to serve as a numerical example of battery selection. For the 120-volt

system, 60 of the lead calcium cells would be connected in series. Quite obviously, vendor data is

necessary to specify a battery.

15.2.5.2 Charger Selection: Satisfactory battery life and service are more dependent on the design

and specification of the charging equipment than on any other external factor. The most costly and

complicated charger is not necessarily the best selection. Shunt wound dc generators were used for years

for charging batteries, but frequent adjustment was required and recharge capability was slow. For

substation service, bridge rectifiers are used. Tube type is still in service, but new installa tions are being

specified with solid-state devices.

The ampere capacity of the charger can be determined using Equation 15-3:

Equation 15-3

Where:

A = Charge capacity (amperes)

L = Continuous load (amperes)

C = Discharge (amperes hours)

H = Recharge time (hours)

EXAMPLE 15-2: Charger Selection

Using the same model as for battery selection, we have:

DC Lights 3.5 Amperes-3 hrs. 10.5 AH

Communications 5.0 Amperes-3 hrs. 15.0 AH

Breaker operations 100.0 Amperes-l min. 1.7 AH

Panel load 5.0 Amperes-8 hrs. 40.0 AH

67.2 AH

Substituting in Equation 15-3 with an 8-hour recharge:

The next largest standard size charger should be selected. If the charger is to be operated at altitudes

above 1000 meters (3300 feet) and above 40°C (104°F) ambient, check vendor data for correction

factors.

The model illustrated here is only to demonstrate a method for battery selection. Also consider substation

expansion in initial battery/charger selection.

Single- and three-phase ac inputs at standard voltages are available. Chargers are commercially available

with standard and optional devices to indicate status and to alarm unusual situations, mainly ac failure.

Refer to vendor data to determine the required devices pertinent to the particular situation under

H

C

A L

1.1

= +

14.24 Amperes

8

1.1 67.2

A 5 =

×

= +
Bulletin 1724E-300

Page 686

consideration. If the selected charger uses a cord, cap, and receptacle for ac supply, specify a locking cap

and receptacle.

Also determine if the battery charger is to function as a battery eliminator. This would allow the battery

to be disconnected for short periods to allow maintenance on the battery without disrupting 120-volt dc

service. Many of the newer electronic and microprocessor devices require a relatively stable dc supply,

with a minimal ac compound associated with the dc supply. The battery while connected into the dc

system provides this filter. If the battery is disconnected, the battery charger filtering may be inadequate

to prevent damage to the relay dc input filters, causing the relays to be damaged. In such cases where the

battery charger is to be used as a battery-eliminator type of charger, compare the ac ripple component

specifications on the dc equipment inputs with the ratings for the battery charger.

15.2.5.3 DC Panels and Wiring: The substation dc auxiliary system should be an ungrounded

system with fuse or circuit breaker panels for dc service. The trend is to use circuit breaker panels.

It is recommended that the positive and negative legs of the dc system be run in separate PVC conduits

from the battery to the first fusible disconnect. This reduces the possibility of the positive and negative

legs of the battery becoming shorted together with no means of clearing the short circuit. Also, the

battery charger should be specified with a ground detection system so positive or negative grounds are

detected. Figure 15-4 is a simplified diagram of such a method.

Relay panels having solid-state equipment cannot sustain voltages higher than 140 volts dc without

possible relay damage. When the battery is being recharged or equalized, the dc terminal voltage could

be in excess of 140 volts. In this case install a 50/60 cell switch and do the recharging at the 50 cell

position. Additionally, circuit breaker operation can cause transient voltage spikes that could possibly

damage equipment connected to the dc bus. Install a surge rectifier across the battery to drain the surge

energy to ground. These features are usually not available from battery charger manufacturers, so it is

recommended that they be installed in the battery room on a wall-mounted wood panel. Figure 15-3

illustrates a simplified diagram of a dc system with these features. Many utilities will remove one or two

cells from the battery bank to avoid the problem of overvoltage while the battery is being equalized.

Complete an evaluation to guarantee the values of current, load, and power supply will stay in specified

levels during the process.

15.3 REFERENCES

ANSI Std. C57.12.25, “Pad-Mounted Compartmental-Type, Self-Cooled, Single-Phase Distribution

Transformers with Separable Insulated High-Voltage Connectors; High Voltage, 34500 GRD

Y/19920 Volts and Below; Low Voltage, 240/120 Volts; 167 kVA and Smaller—Requirements.”

ANSI Std. C57.12.26, “ Pad-Mounted Compartmental-Type, Self-Cooled, Three-Phase Distribution

Transformers for Use with Separable Insulated High Voltage Connectors; High Voltage, 34500

GRD Y/19920 Volts and Below; 2500 kVA and Smaller.”

Mantell, C.L., Dr., Batteries and Energy Systems, 2nd ed. New York: McGraw Hill Book Company,

1983.

National Fire Protection Association (NFPA) Std. 70, NEC, Article 384, “Switchboards and

Panelboards.”

National Fire Protection Association (NFPA) Std. 70, NEC, Article 700, “Emergency Systems.”
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Figure 15-4: Typical Battery Ground Detection System
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CHAPTER 16

CONTROL HOUSES

16.1 INTRODUCTION

As substations increase in voltage, size, and complexity, the necessity for supplemental equipment such

as relays, meters, controls, batteries, communications equipment, and low-voltage distribution equipment

also increases. For small distribution substations, this equipment can usually be contained in

weatherproof enclosures or control cabinets. For larger substations, separate equipment housing is

necessary.

A control house provides a weatherproof and, if required, environmentally controlled enclosure for

supplemental substation equipment. Additional space can be provided for workshops, equipment testing

and repair, storage areas, and lavatory facilities.

Medium- and low-voltage switchgear can also be contained within control houses, or this equipment may

be contained within weatherproof enclosures dedicated to that purpose. Switchgear is discussed in more

detail in Section 5.4.

16.2 CONTROL HOUSE CONSTRUCTION

This section discusses general aspects of the control house construction. It does not attempt to cover all

details of construction. RUS 1724E-400, “Guide to Presentation of Building Plans and Specifications,”

presents details that will apply and should be consulted.

16.2.1 Foundation

The control house foundation typically consists of a spread footing with either masonry blocks or cast-inplace walls. The footing is designed for an allowable bearing capacity based on soil data. If soil data is

not available, a maximum bearing of 48 kPa (1000 lb/ft2) can be used. The footings are installed below

frost depth and in accordance with local building codes and practices.

Drilled piers are an alternative to spread footings. Drilled piers are especially applicable for preengineered metal buildings with structural supporting bases that can rest directly on the piers without

requiring a concrete floor slab. Soil data is necessary for determining the required depth, diameter, and

reinforcing of the piers.

Damp-proofing of foundation walls is desirable, especially if concrete block is used. If a basement level

is constructed, damp-proofing should be provided. Footing drains are usually provided when a basement

level is constructed.

All foundation walls should be insulated with a 5.1-cm (2-inch) thickness of rigid insulation for energy

conservation. It is preferable to install the insulation on the inside of the walls, although the outside is

acceptable.

16.2.2 Floor

The control house floor is typically a floating concrete slab 12.7 to 15.2 cm (5 to 6 inches) thick
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reinforced with welded wire fabric, deformed steel bars, or a combination of both. The finished floor

elevation is usually 10.2 to 20.3 cm (4 to 8 inches) above the finished grade outside the control house.

The base beneath the floor slab should be 10.2 cm (4 inches) of compacted sand or gravel, thoroughly

mixed and compacted sand or gravel, or thoroughly mixed and compacted natural soil. A 0.15 mm

(0.006-inch) thick plastic film vapor barrier should be installed between the floor slab and the base.

The method for cable routing in the control house has to be considered before finalization of the floor slab

design. Cable trenches can be formed into the floor slab, or false floors can be installed providing access

to large areas below the finished floor.

16.2.3 Superstructure

The control house superstructure should be constructed from fire-resistant, low-maintenance building

materials. Most control houses presently being designed and constructed are of the pre-engineered metal

or masonry block type. Figures 16-1 through 16-3 show examples of some control building

superstructure types.

Figure 16-1: Pre-Engineered Metal Control Building (Coffeyville, KS)

The pre-engineered metal building is the easiest to procure and erect. The manufacturer can design and

fabricate the required building components when given the building size; wind, snow, and ice loads; and

any special requirements such as additional roof loads for suspended cable trays or other equipment.

Masonry buildings constructed of block masonry are most economical when masonry module dimensions

are used to size the building and the building openings.
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Figure 16-2: Typical Masonry Block Control Building

Figure 16-3: Architecturally-Pleasing Masonry Building (Rochelle)

Decorative block can be used as an inexpensive method to improve external appearance. Block cores

should be filled with vermiculite or equivalent insulation.
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Two types of roof systems are commonly used for masonry buildings: precast, prestressed concrete

panels; and steel joists and steel decks. A sloping roof is recommended for both systems and can be

obtained by pitching the roof deck or installing tapered roof insulation. The roof membrane has to be

compatible with the slope. For the slopes of 8.3 cm/m (1 in./ft) and less, built-up pitch and slab is

commonly used. For greater slopes, gravel is used.

The control house should be equipped with at least one double door, possibly with a removable transom,

conveniently located to facilitate equipment entry and removal. In certain circumstances a second exit

needs to be installed in the control house. The National Electrical Safety Code (NESC) states: “If the

plan of the room or space and the character and arrangement of equipment are such that an accident

would be likely to close or make inaccessible a single exit, a second exit shall be provided.” The

National Electrical Code (NEC) also defines specific requirements for a second exit. The doors should

include locking devices, astragals to prevent water from entering, and adequate weatherstripping and

hardware to permit a rapid exit from the control house.

Adequately ventilate the battery area, either by a natural or powered ventilation system, to limit

accumulation of hydrogen gas to less than an explosive mixture. A powered ventilation system needs to

be annunciated to indicate ventilation failure.

Provide portable or stationary water facilities or a neutralizing agent for rinsing eyes and skin in the

battery area in addition to proper eye protection and clothing.

Locate and mark adequate fire-extinguishing equipment in the control house.

Windows can be provided, if desired, in office and lavatory areas. Battery rooms and control and

metering areas do not need windows.

Consider adequate methods for building insulation. These methods include use of insulated wall panels,

ceiling insulation, storm doors, and windows, and weatherstripping around all openings.

Metal buildings are shop painted and require only minor field touch-up after erection. Masonry buildings

may be left unpainted or may be painted with portland cement or latex paint. Tint all prime coats to

match the finished coat.

16.3 CONTROL HOUSE LAYOUT

16.3.1 Control and Relay Panels

Most relaying, metering, and control equipment is mounted on fabricated control and relay panels

installed within the control house. A variety of panel types is available to suit individual requirements.

Figures 16-4 and 16-5 show examples of various panel layouts.

Single vertical panels can be used, particularly for distribution circuits where space requirements are

minimal. The relaying, metering, and control equipment can all be mounted on one panel, allocating a

separate panel for each circuit. In some instances, two circuits may share the same panel.

Double or duplex panels are commonly used for higher voltage circuits, necessitating additional space for

equipment mounting. Normally, these panels are arranged in two parallel rows with the panel backs

facing each other. In this configuration, operating, instrumentation, and control equipment for a circuit is

installed on the front of one panel, and the corresponding relaying equipment for the same circuit is
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Figure 16-4: Typical Relay/Control Panel Layout. Figure 16-5: 19-Inch Rack-Mount Relay/

 Note microprocessor, electromechanical relays, and mimic bus. Communications Equipment (PSI)
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installed on the front of the panel directly to the rear. In some instances, two circuits may share the same

control and relaying panels.

Some equipment such as static relaying systems and communications equipment is available mounted in

racks. Consequently, separate relay and/or control panels are not required for this equipment.

Modern SCADA and substation automation schemes may require space for installation of a PC with

monitor and keyboard, as well as programmable logic controllers and data highway interface modules.

This equipment can often be rack-mounted or installed in control panels, as appropriate.

The trend is toward more compact equipment arrangements that often reduce overall control house size.

Individual three-phase microprocessor relays can replace three single-phase electromechanical relays and

associated voltage, current, and power meters, all in one case. Compact relay and programmable logic

controller designs can be mounted on 48.26-cm (19-inch) racks.

To facilitate operation, panels are located in an arrangement that conforms as closely as possible to the

actual equipment and circuit layout in the substation yard. To assist in circuit location and operation,

mimic buses are sometimes used on the control panels, particularly for large complex substations. The

mimic buses identify the bus and circuit arrangements. Mimic buses may be implemented on screens

viewed from a PC monitor. When practical, position meters at eye level and switches at a convenient

operating level. Locate recording meters for ease of viewing and chart replacement. Locate relays

beginning at the tops of the relay panels and working downward. Relays with glass covers should not be

located within 12 inches of the floor to avoid inadvertent breaking of the glass. Locate operating switches

at convenient heights near the center of the boards. Require nameplates for all devices. Provide ample

space for relay installation, removal, operation, and testing.

Panel construction can include removable front plates for device mounting. Panels may also include

19-inch rack mounting facilities. Many of the newer relays and items of accessory equipment are

designed to fit into 19-inch racks. Cover plates may cover space reserved for future use. In this way,

only a new predrilled plate is required when changing out a device or modifying the configuration.

Cutting, drilling, or covering openings in the panels is eliminated.

Panel wiring is accomplished on the backs of the panels. Devices are interconnected and wired to

terminal blocks, as required, for operation and connection to devices on other panels. Panels can include

small sections perpendicular to the main section at each end for installation of terminal blocks, fuse

blocks, or small auxiliary devices. Cable connections from the equipment in the substation yard can be

made directly to terminal blocks mounted on the panels or to strategically placed terminal cabinets.

Interconnections between the terminal cabinets and the panels can then be made with single conductor

wire.

Anchor panels to the floor in such a way as to facilitate relocation to coincide with yard equipment and

circuit relocations.

Panel arrangement in the control house should permit ready accessibility to the backs of the panels.

Some vendors of pre-engineered buildings can provide completely wired and tested control and relay

panels and auxiliary ac/dc power systems as part of the building package. In this case, custom-designed

relay and control schematics are submitted to the building vendor. The building vendor fabricates the

panels, provides the relays and controls, wires the panels, and tests the complete installation. In this way,

the entire panel line-up can be witness-tested in the factory. The complete building system is shipped to
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the site, fully tested. Only the external wiring from the building to the outdoor equipment has to be fieldinstalled.

16.3.2 DC Equipment

Substation dc equipment located in the control house normally consists of the battery, battery charger,

monitoring and control devices, and distribution panelboard. The battery should be located in a separate

room where practical. If the battery cannot be located in a separate room, it should be located so that

electrical switching devices and receptacles are not in the immediate vicinity, ventilation is adequate to

prevent gas accumulation, and live parts are protected from accidental contact. The battery charger,

monitoring and control devices, and distribution panelboard are normally located in the control and relay

room to facilitate cable routing and equipment maintenance.

Detailed design requirements and procedures for the substation dc system can be found in Chapter 15.

16.3.3 AC Equipment

A low-voltage ac system is provided in the substation for lighting; convenience outlets; heating,

ventilating, and air conditioning (HVAC) equipment; and miscellaneous control functions.

Strategically locate convenience outlets throughout the control house to provide adequate accessibility.

Provide the workshop and testing area with a high-capacity ac source and a three-phase source.

An ac distribution panelboard located inside the control house is used to supply the indoor lights,

convenience outlets, HVAC equipment, and other devices.

For greater reliability, two separate sources may be provided for the ac system service. These sources are

often fed through a manual or automatic transfer switch so that ac system power can be restored if one

source fails.

Chapter 15 contains additional information concerning design of the substation ac system.

16.3.4 Cableways

Cable routing can be accomplished by using any of several methods.

16.3.4.1 Cable Trenches: Cable trenches are formed into the concrete floor slab and are covered with

metal plates. The covers should be flush with the finished floor when in place. The sizes and locations of

the cable trenches are based on the quantities of cables and locations of panels and equipment to be

interconnected. Usually, a cable trench is located adjacent to the backs of the control and relay panels to

facilitate panel interconnections. With duplex panels, it may be desirable to use the entire space between

the front and rear panels as cable trench, depending on circuit quantities.

16.3.4.2 False Floors: False floors are useful when large open areas are desirable for cable routing.

Lightweight removable floor panels installed on adjustable pedestals are positioned in areas requiring

extensive cable interconnections or where future plans dictate a large amount of cable rerouting. The top

of the removable panels should be flush with the finished floor.
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When cables are mounted under false floors, establish routes and paths in which cables should be routed.

This will allow the separation of circuits as required to maintain system reliability based on duplicate

circuits. If circuits in one area are damaged, other undamaged circuits in the other parts of the building

are likely to keep the substation in service.

16.3.4.3 Conduits: Conduits can be used for cable routing in floors, along walls, and for cable

entrance into the control house.

Conduits are available in plastic, aluminum, and steel. Each of these types may be used in control houses

for wire containment to convenience outlets, lighting fixtures, and other control house auxiliary power

equipment.

Plastic conduit is easily installed and is available in a variety of sizes. Take adequate physical and

thermal precautions when using plastic conduit to ensure safe operation.

Metallic conduits of aluminum and steel are widely used as control house cableways. Intermediate- and

heavy-walled steel conduit provide excellent physical protection. The installed costs, however, may be

relatively high because of the extensive labor required for installation. The installed cost of rigid

aluminum conduit may be somewhat less than that for steel. A lower installed cost may be realized by

using thin-walled steel conduit (i.e., electrical metallic tubing) since it is less expensive and easier to

install.

16.3.4.4 Wireways: Wireways are sheet-metal troughs used for routing groups of power circuits

around a control house to feed various branch circuits. Conduit is used between the wireway and the

devices.

Wireway offers the advantage of laying rather than pulling the cable into position and the ability to

change or reroute circuits easily. Wireway is available with hinged or removable covers in a variety of

lengths and sizes. Select and install wireway in accordance with the National Electrical Code.

16.3.4.5 Cable Trays: Cable trays can be used for overhead routing of cables to and between control

and relay panels. Expanded metal or ladder-type trays provide the best facilities for conductors entering

and leaving the trays. An advantage of cable trays is the ability to lay rather than pull in the conductors.

Suspended cable trays, however, prevent extensive use of this technique because of support locations. A

large variety of types, sizes, and fittings is available to suit individual requirements. Cable tray should be

selected and installed in accordance with the NEC and NEMA Standards.

16.3.5 Cable Entrance

Control and power cables are brought into the control house through windows, sleeves, or cable pits. The

windows are square or rectangular openings, usually through the foundation wall but possibly above

grade. The window openings enable many cables to be pulled without interference. To protect the cables

during pulling, the windows should have smooth surfaces and beveled or rounded edges. After cable

pulling, split sleeves can be installed around the cables and grouted into place. Occasionally, the

windows are left open to facilitate future cable installation. Heat loss through these openings should be

considered. Provide additional windows for installation of future cables. The windows can be

constructed and bricked up to be opened when required.

Cable sleeves can be used above or below grade. The sleeves are usually cast into place during

construction of the foundation wall or installed during construction of the superstructure. Pitch the
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sleeves to drain out of the building. Provide covers over the cables. Install spare sleeves during initial

construction.

Cable pits may be cast-in-place concrete or masonry openings through the control house foundation to

permit access to the inside at floor level. Install a cover over the pit and provide a means to drain water.

16.3.6 Lighting

Fluorescent lamps are generally used for lighting in control houses. The trend is toward energy-saving

lamps and energy-saving electromagnetic or electronic ballasts. Install lighting to eliminate, as much as

possible, reflection and glare from meters, relays, and monitoring screens.

An emergency dc-operated incandescent system is recommended for most control houses. This system

can be operated in case of failure of the ac system. It can be operated from battery-pack units or from the

station battery system.

Additional information concerning control house lighting can be found in Chapter 15.

16.3.7 Control House HVAC Systems

To maintain the functions and accuracy of electrical equipment installed in the control house, HVAC

systems may be desirable.

In areas requiring heat only, unit electric space heaters are positioned throughout the control house for

balanced heating. If both heating and cooling are required, electric heat pumps can be used. Several

small units, or one large unit with a duct system for air distribution, can be used. Supplemental electric

resistance heating coils may be required for heating in colder areas.

Baseboard radiation heating units can be used in rooms not reached by the main heating system. These

rooms include offices, lavatories, and storage rooms. The battery room is sometimes left unheated;

however, maintenance of battery temperature close to 32oC (77oF) will prolong the life and capacity of

most battery systems.

Temperature control levels may vary because of several requirements. Operating ranges of equipment

have to be considered as well as economics. It is recommended that consideration be given to a dual

control. Most stations will be unattended and, therefore, a normal personal comfort level is not required.

However, for maintenance reasons, comfort levels are necessary.

The system then would normally maintain a minimum level based on equipment requirements with

controls designed so that one or more additional units are used to raise the temperature to a comfort level

suitable for maintenance personnel. In smaller control houses, this may be accomplished during

maintenance periods by raising the thermostat controlling a small system.

If the control house is to be heated only, it is usually desirable to install power ventilation equipment for

air circulation. Size the system for three to five air changes per hour. Place power-operated,

thermostatically controlled roof ventilators and manually operated wall louvers to achieve good air

circulation. Position wall louvers so that equipment does not interfere with air circulation. Provide

fusible links to close the louvers in case of fire.
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It is advisable to provide ventilation that will maintain a positive pressure within the control house at all

times to prevent dust from entering through doors and other openings, and prevent accumulation of

combustible gases. If control house air conditioning is used to provide positive air pressure, then the vent

should remain open and fan should run continuously. This also applies if the unit is a heat pump.

The isolated battery room should be equipped with a gravity roof ventilator to remove corrosive and

combustible gases. Do not use power-operated roof ventilators.

16.3.8 Control House Plumbing

Control houses may require plumbing for stationary eyewash facilities. Additionally, very large, major

locations may warrant a shower, lavatory, drinking fountain, and maintenance sink.

A water supply, when required, may be obtained from an existing system or a private well on the

substation site. A well should be capable of supplying 22 liters/minute (5 gpm) at a minimum pressure of

172.4 kPa (25 psi).

Most substations with toilet facilities will require septic tank and drain field systems. These systems are

designed and installed in accordance with local codes and regulations, obtainable through county health

departments. Additional information can be found in the Manual of Septic Tank Practice.

Separation between a water well and a septic tank and drain field should be in accordance with local

ordinances. In the absence of such information, provide a minimum of 15.2 meters (50 feet).

16.3.9 Communications

A commercial telephone is usually installed in the control house for external communications.

Additionally, system telephones or voice channels over carrier systems may be used for system

communications.

Larger installations may include substation automation systems or SCADA for remote control and

monitoring of substation equipment.

For a detailed discussion concerning substation automation, see Chapter 14, and for a detailed discussion

concerning substation communications, see Chapter 17.

16.4 REFERENCES

ANSI Std. C2, National Electrical Safety Code (NESC).

National Fire Protection Association (NFPA) Std. 70, National Electrical Code.

RUS Std. 1724E-400, “Guide to Presentation of Building Plans and Specifications.”

U.S. Department of Health, Education and Welfare, Public Health Service, Manual of Septic Tank

Practice, Publication No. 526.
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CHAPTER 17

COMMUNICATIONS

17.1 INTRODUCTION

Since substations are part of large interconnected power systems, methods of voice and data transmission

among the various system parts are necessary to maintain satisfactory operation and control.

Communication systems are used in protective relaying schemes to initiate tripping control schemes of

power circuit breakers; in supervisory control systems to operate remote equipment, for transmission of

data indicating equipment status and system conditions, and for voice communications for system

operation and maintenance.

Table 17-1 matches the various substation communication applications with their appropriate

communication methods.

Table 17-1:

Substation Communication Methods vs. Applications

METHODS

APPLICATIONS

Power Line CarrierAudio ToneMicrowaveFiber OpticsWire LineSatellite (VSAT)

Relaying Υ Υ Υ Υ Υ

SCADA / Automation Υ Υ Υ Υ Υ

Voice Υ Υ Υ Υ

Telemetering Υ Υ Υ Υ Υ

17.2 APPLICATIONS

17.2.1 Relaying

Many relay schemes now in use require information to be exchanged among all the terminals on a

transmission line to effect high-speed tripping over 100 percent of the line. Since these terminals are

often many miles apart, some form of two-way communication channel has to be established between

them. The information to be transferred is relatively simple two-state data in most cases and can utilize

the more basic forms of modulation.

17.2.2 SCADA

Most utilities have a centralized energy control center from which the electric power system is remotely

operated. It is usually expected that circuit breakers and tap changers will be monitored and controlled,

generation monitored and controlled, capacitor banks may be monitored and controlled, alarms reset, and

miscellaneous other on/off-type functions effected over distances ranging from a mile or less to hundreds

of miles.
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The energy control center receives various types of data from the power system. This data includes

breaker status, tap changer position, amps, volts, watts, VARs, and other quantities, both digital and

analog. Again, the data travels over distances ranging from a few miles to several hundred.

In most modern energy control centers, the remote data monitoring and system control functions for

substation applications are performed by a SCADA system. These systems consist of a central host

computer system at the energy control center, referred to as a master station, and RTUs located in the

substations. There is a trend toward increasing intelligence at the substation level (see Chapter 14,

Substation Automation) where the traditional RTU is being replaced with IEDs in a LAN arrangement.

Regardless of the level of intelligence resident at the substation level, some form of real-time

communication is required between the master station and the RTU or remote electronics.

17.2.3 Telemetering

In some instances where a computer-based SCADA system is not available or justified, it is desirable to

transmit discrete power system data from the substation to the energy control system in an analog format.

For example, analog quantities such as amps, volts, watts, or VARs may be required to drive a remote

readout or chart recorder. Likewise, discrete system status values such as breaker position may be

required to drive a remote annunciator. In these cases a communication method is required that can

directly accommodate analog signals that may include scaled milliampere or voltage, or frequency-shift

audio.

17.2.4 Voice

Power system operation and maintenance require the use of voice communication for daily operation and

functioning of the power network. Voice communications are required between fixed points of operation

and for mobile maintenance crews. The transmission of voice signals may take place via cable, radio, or

the power system itself. The transmission facilities may make use of either leased systems or

cooperative-owned facilities.

17.3 METHODS

17.3.1 Power Line Carrier

Power line carrier, one of the more common communication means found in power systems in the past, is

now being displaced in many applications with fiber optics. But power line carrier may still be used for

relaying and voice applications, and lower speed data.

Carrier signal frequencies range from 30 kHz to 500 kHz and are coupled directly to the power line

through a coupling capacitor, a device that frequently doubles as a relaying and/or metering potential

source. The signals are transmitted at a relatively low power level, 100 watts or less, typically 10 watts,

and hence do not radiate appreciably from the power line. They have to be received in a similar way

through a coupling capacitor connected to a carrier receiver at the other end of the line. See Figure 17-1.

To confine the carrier signal as nearly as possible to one line section and to keep the signal from being

effectively shorted through the high capacitance of the station bus and connected transformers, line traps

are installed on the station side of the coupling capacitor to block the carrier signal.
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Figure 17-1: Typical Carrier System

Line traps are generally simple parallel L-C resonant circuits with the inductance in series with the

coupled phase of the line. This inductance is rated to match the BIL, through current capability and shortcircuit withstand capability of any other major equipment on the line, and so is physically large.

17.3.1.1 Tuning Elements: Besides the line trap and coupling capacitor, there are several other

components involved in tuning and matching the transmitter output to the power system.

17.3.1.1.1 Line Tuner Unit (LTU): The coupling capacitor provides the path for the carrier signal to

reach the power line itself. Since there are capacitive and inductive elements in the coupling capacitor

and in the power system, a tuning network has to be provided to match the transmitter output impedance

to the impedance seen at the coupling capacitor input. This device, the line tuner, comes in several

different configurations, depending on the tuning method selected. In addition, the line tuner assembly

contains protective elements such as a gap with capacitor and a grounding switch. The assembly may be

mounted in the coupling capacitor base or in a separate weatherproof cabinet.

17.3.1.1.2 Hybrid: A hybrid is a special transformer used to combine carrier transmitter and receiver

inputs and outputs in such a way that transmitters and receivers may be connected to the same line tuner

without mutual interference. A hybrid has one output and two inputs and is bi-directional so that the

output may be connected to the line tuner and the inputs to a combination of transmitters and receivers
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without the receiver input being overloaded when the transmitter operates. Hybrids may be stacked; that

is, one of the two inputs may be connected to another hybrid output resulting in three isolated inputs to

the same line tuner. A limitation to this connection is that each hybrid reduces the power level by 3dB.

Thus, two stacked hybrids result in only one quarter of the transmitter power reaching the line tuner from

each hybrid terminal.

17.3.1.1.3 L/C Units: Various combinations of series and parallel connected capacitors and inductors

are available for use with special tuning schemes or as additional tuning elements in the line tuner

package. In general, the manufacturer’s recommendations should be followed in applying these units.

17.3.1.2 Tuning Methods: There are three basic methods of tuning carrier transmitters and receivers

to the power line.

17.3.1.2.1 Single-Frequency Resonant Tuning: A single-frequency resonant-tuned installation utilizes

a combination of inductances and capacitances in the line trap and line tuner resulting in a combination

frequency response that exhibits a single sharp peak centered about the selected frequency. Adjustment is

available in both the trap and tuner, but both have to be ordered by specifying a range of frequencies

according to the manufacturer’s catalog data. Single-frequency resonant tuning is used less frequently as

the available carrier spectrum becomes more crowded and it becomes more common to have several

frequencies for multiple uses on a single line. Single-frequency tuning results in the lowest transmission

losses, but is least flexible from the standpoint of subsequent additional carrier frequencies for control,

telemetering, and relaying. Figure 17-2 shows a typical graph of the frequency response for a singleFigure 17-2: Single-Frequency Resonant Tuning
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frequency resonant tuned installation.

17.3.1.2.2 Double-Frequency Resonant Tuning: This coupling method is identical to single-frequency

tuning except that there are two closely spaced sharp peaks in the frequency response. The losses are

somewhat greater, but the availability of two frequencies can compensate for this small disadvantage. In

addition, it is possible to use as many as four frequencies if they are selected so that none is more than the

manufacturer’s tolerance away from a peak. This is done by using hybrids on each of the two

frequencies. Figure 17-3 shows a graph of a typical double-frequency resonant-tuned system.

Figure 17-3: Double-Frequency Resonant Tuning

17.3.1.2.3 Wideband Tuning: The frequency response of a wideband tuning package is a relatively

low peak spanning a wide range of frequencies. The obvious advantage is that a number of frequencies

may be fed through the same line tuner.

A disadvantage is greater attenuation in the tuning package through more leakage to the bus side and

higher impedance in the tuning package. The wideband line tuner is a simple high-pass filter, and series

L/C units are frequently used to separate the various transmitter–receiver combinations. Hybrids should

still be used to separate transmitters and receivers. Wideband tuning is becoming more popular in spite of

the increased losses because of the need to put more functions on a line as relaying schemes become more

elaborate and remote control and data functions are added. Figure 17-4 shows a graph of a typical

wideband-tuned system.

17.3.1.3 Modulation Types

17.3.1.3.1 On/Off: This simplest form of putting information on the carrier wave is only used with

directional comparison or phase comparison blocking relaying. As its name implies, the carrier

transmitter is normally de-energized. When it is keyed, it simply sends an unmodulated carrier that the

receiver interprets as a blocking signal. Voice modulators are usually added so that the transmitter carrier
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Figure 17-4: Wideband Tuning

can be modulated and thus provide an extra emergency or voice communication channel. Since a received

signal in such a relay scheme does not result in a trip or attempted trip, it is perfectly safe to voice

modulate the carrier.

The chief disadvantage of on/off carrier is its quiescent nature. The carrier is off most of the time and, if

a component fails during this period, there will be no indication of the failure until the scheme is called on

to operate. If it has to block for an external fault at that time, a false trip can occur. Many utilities avoid

this situation by applying a carrier checkback scheme. This scheme periodically initiates a characteristic

series of carrier bursts from one end of the line. The other end recognizes the test transmission pattern

and responds similarly. Receipt of this response at the initiating end verifies the system can transmit and

receive data.

17.3.1.3.2 Frequency Shift Keying (FSK): This modulation method finds widespread use in most

relaying, control and data transmission schemes. An unmodulated carrier is sent continuously and is

termed the “guard” or “space” signal. When a trip or data signal is desired, the guard or space signal is

shifted up or down by a small percentage and the shifted signal is termed the “trip” or “mark” signal. In

general, relaying literature uses the trip and guard nomenclature, while mark and space will be found in

most data and control literature. Trip and guard signals are separated by very accurate filters on the

inputs of the receiver.

The advantage of this scheme, particularly for relaying, is the channel monitor capability provided by the

continuous transmission. If, at any time, the guard signal disappears without an immediate trip signal, the

channel is presumed to have failed and an alarm can be energized. Additional channel security can be

obtained by biasing the receiver discriminator to the guard side. A white noise burst, therefore, will

produce a small net guard output that can be overcome by a transmitted trip signal even during the noise
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burst. This feature makes it possible to drive an FSK carrier signal through an arcing fault on the

protected section.

17.3.1.3.3 Single Sideband (SSB): This modulation type is used extensively in other countries where

its multi-channel capability is important because of the lack of a reliable and extensive telephone network

such as exists in this country. In those areas, power systems have to provide their own basic voice

communications, and the power system itself is an excellent medium. Here, however, SSB carrier has

found little use primarily because of its high cost.

Basically, the carrier signal is modulated with voice or data signals, resulting in the transmission of the

carrier plus two sidebands containing the carrier plus the modulation frequency and the carrier minus the

modulation frequency, which is conventional. Since all the desired information is in each sideband, the

carrier and either sideband can be eliminated resulting in a suppressed carrier, single-sideband signal

having one-half the bandwidth of a transmission. It is then possible to transmit two voice channels in the

bandwidth formerly occupied by one voice channel.

Sophisticated equipment is available whereby, with a system of subcarrier frequencies, many channels in

multiples of two can be transmitted.

17.3.1.4 Power Line Carrier Reference: The application of power line carrier is a complex subject

requiring more space than is available in this bulletin. For a more thorough review of power line carrier

application and design, see the following:

1. “GE Protection and Controls Relaying Communication Channels Application Guide,”

GET-8034.

2. Pulsar Technologies, Inc., “Power Line Carrier Channel & Application Considerations for

Transmission Line Relaying,” Pulsar Document No. C045-P0597.

17.3.2 Audio Tone

Audio tone equipment operates in the frequency range from 1000 Hz to about 3000 Hz. Frequency shift

keying is the only modulation type available; voice modulation cannot be used.

Audio tone is used primarily as a short-distance medium over wire lines. FSK modulation provides

ample security, and, in most cases for most telephone applications, reliability is also high. Additional

security is available in the form of broadband noise detection and frequency translation detection.

Broadband noise detection is simply a wideband receiver with no corresponding transmitter. If this

receiver output exceeds a certain level, a noise alarm is actuated and all channels squelched off.

Frequency translation detection utilizes a single unmodulated channel. If the output from this receiver

drops, the translation alarm is actuated. This feature is most commonly used with microwave or other

multi-channel configurations where a problem in the multiplex equipment can cause frequency shifts.

Audio tone always requires another communication transmission medium to carry the audio (wire line,

microwave, optical fiber, power line carrier, or shield wire).
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17.3.3 Carrier or Audio Tone on Shield Wire

The chief distinction of this method is the medium rather than the equipment. Transmitters and receivers

are the same as those employed in other carrier and audio tone systems. However, in this scheme they are

coupled to insulated transmission line shield wires. EHV shield wires are sometimes insulated to reduce

losses from induced circulating currents. The usual insulation level is 15 kV, with gaps on the insulators

to conduct lightning strokes to ground.

The coupling is usually between two such insulated shield wires through a special coupler containing

matching networks, capacitors, protective gaps, and an insulating transformer. This equipment is required

to protect the communications equipment from the high energy levels present on such shield wires during

lightning strokes.

In general, this method is not used for protective relaying because of the uncertainty of successful

communication during lightning strikes. It has found more application for data and voice

communications as a low-cost alternative in those cases where the decision to insulate the shield wires

had already been made on the basis of inductive loss prevention.

17.3.4 Microwave

Microwave systems have been used extensively on power systems in the past few decades as the

requirements for dedicated voice and data communications increase. Because of the high cost of the RF

equipment and antenna towers, microwave is generally used where there is a requirement for a large

number of channels between two points. Transmission is line of sight only, necessitating intermediate

repeater stations for long paths. The cost per channel is relatively low as long as most of the available

channels are used and the path length is not excessive.

Microwave systems presently employed use transmission frequencies of 960 MHz and higher, which

accounts for the high channel capacity and line-of-sight transmission. There is relative freedom from

many forms of interference, but path fading and other forms of distortion can be problems. Most

microwave systems require a license from the Federal Communications Commission (FCC) to operate.

17.3.4.1 Analog vs. Digital Microwave: Both analog and digital microwave systems are in use

today. Analog microwave systems accept audio input signals that are frequency multiplexed together to

form an analog baseband signal that is then used to frequency modulate the higher frequency microwave

carrier. Digital signals have to be converted to analog through the use of modems before they can be

transmitted on an analog microwave system, which results in an inefficient use of the bandwidth. Analog

microwave systems are available in capacities from as few as one to as many as 600 channels.

The increasing emphasis on data transmission is driving users toward increasing utilization of digital

microwave. The majority of new microwave systems installed today are digital. Unlike analog

microwave, digital microwave employs a digital time-division-multiplexed (TDM) baseband that is used

to digitally modulate the microwave carrier. Analog (voice or audio) information is converted to a data

stream using pulse-code modulation (PCM) and then fed into the microwave TDM baseband. Data

signals ranging from low-speed asynchronous (1200 bits per second) to high-speed synchronous

(56 kilobits/second, 1.5 megabits/second, and higher) can be inserted directly onto the TDM baseband

without any intermediate modulation as would be required in an analog system. In this way, data is

handled much more efficiently than in the analog scheme, and voice is handled equally well. This results

in digital microwave systems having a lower per channel cost than analog. Digital microwave systems
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are available in capacities from as few as one to as many as 2016 channels. Figure 17-5 shows a 6 GHZ

digital microwave radio and antenna mounted on a substation box structure.

Figure 17-5: 6 GHz Microwave Terminal Mounted on Substation Box Structure

Power utilities typically purchase microwave radios in a monitored “hot-standby” configuration for added

reliability. Hot-standby means that each radio contains two transmitters and two receivers, one set for

primary and one set for backup, with monitoring and switching circuitry that automatically switches to the

backup unit in the event the primary unit fails. For protective relaying on high-voltage transmission lines,

it is common to use a microwave system in parallel with power line carrier for maximum security.

17.3.4.2 Multiple Address Systems: MAS are specialized microwave radio systems that are

designed specifically for SCADA systems. MAS operate in the 900 to 960 MHz band and can employ

analog or digital modulation technology. Each MAS provides a single channel of communications that is

shared among four or more remote sites. The radio channel essentially behaves like a party line, so only

one site can access the channel at any given time. Therefore, MAS is best suited to SCADA

communications where a host computer sequentially polls remote terminal units using a master–slave

protocol. This technology is widely used by electric utilities for substation SCADA communications in

cases where other non-SCADA voice, data, and relaying applications are not needed. MAS is not suitable

for telephone or protective relaying applications. Figure 17-6 shows a typical MAS installation on a rural

substation control house.
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Figure 17-6: MAS Microwave Antenna on Substation Control House
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17.3.5 Optical Fiber

Optical fiber has become the communications technology of choice for most electric utility substation

communications. Optical fiber offers the advantages of immunity to electrical sources of interference and

noise, and extremely large information-carrying capacity. (The information-carrying capacity of optical

fiber is far greater than that required in a typical substation.)

17.3.5.1 Fiber-Optic Cables: Fiber-optic cables are available in a variety of configurations including

aerial and underground cables. Two of the most popular types of cable used by electric utilities are

optical ground wire (OPGW) and all-dielectric self-supported (ADSS) cables. In the case of OPGW,

optical fibers (numbering typically from 6 to 48 fibers) are placed inside a specialized conductor that

serves as both a fiber-optic communications facility and a ground wire or shield wire. Since the shield

wire is typically installed on the top of the transmission line towers above the energized line, ground

clearance problems that often prevent the installation of a communications cable beneath the energized

line (i.e., underbuild) are avoided. Also, for newly constructed lines, the incremental costs of a

conventional shield wire (a cost that is avoided with OPGW) can be deducted from the costs of the

OPGW, increasing the economic feasibility of the OPGW installation. Special suspension and

termination hardware is required for the OPGW conductors. Figure 17-7 shows a typical OPGW splice

mounted on an A-frame transmission structure.

ADSS cable finds its widest application by electric utilities on low-voltage distribution and

subtransmission poles (69 kV or less), but can be also used on high-voltage transmission lines where

clearances will allow. ADSS cables are self-supported, requiring no supporting messenger. The cables

are all-dielectric (containing no metals) so they can be safely installed in the supply space on electric

utility poles by properly trained line personnel, and they can be routed directly into an electrical

substation from outside the substation ground mat without introducing a ground potential rise hazard.

These cables can contain as few as 4 or as many as 216 fibers and can be manufactured for unsupported

spans of up to several thousand feet.

Other cable types that are commonly used include aerial/duct cable (all-dielectric or steel-reinforced) and

rodent-resistant cables for direct burial.

17.3.5.2 Fiber-Optic Technology: Fiber-optic transmission systems are primarily digital, utilizing

TDM technology as is also used with digital microwave (see Section 17.3.4.1, Analog vs. Digital

Microwave). Optical transceivers are available in capacities ranging from as few as one channel to many

thousands. Fiber-optic transmission equipment from some manufacturers has been designed specifically

for substation applications, supporting voice, data, and protective relaying functions. These specialized

substation multiplexers are typically available at capacities of DS1 (1.544 megabits per second or up to 24

voice channels), SONET OC-1 (51.84 megabits per second or up to 672 voice channels), and SONET

OC-3 (155.520 megabits per second or up to 2016 voice channels). These systems include advanced

features such as embedded network surveillance, control, and management software, and fault-tolerant

rings. Figure 17-8 shows fiber-optic multiplexers installed in a substation for telephone, SCADA, and

pilot-wire relaying applications.

Another specialized application for optical fiber in substation communications is GPR isolation of

metallic wire communications circuits. Because GPR can occur in electrical substations during short

circuits on the electrical power system, metallic facilities such as telephone lines that enter the substation

from outside the ground grid has to be electrically isolated from the substation ground influence. Since

optical fibers do not conduct electricity, fiber-optic entrance links can be used to electrically isolate these

metallic circuits in lieu of the more insulating transformers and mutual drainage reactors that have
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Figure 17-7: OPGW Splice on Deadend Structure Figure 17-8: Fiber-Optic Multiplexers (Above)

in Substation and Fiber-Optic Patch Panel (Below)
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been traditionally used for this purpose. Special fiber-optic isolators are commercially available for this

purpose.

17.3.6 Wire Lines

Wire lines leased from the telephone company are used in many cases for routine voice and data traffic.

Wire lines entering substations for the purpose of communications, control, and protective relaying

require special attention for high-voltage protection. These circuits may be used in the event of a power

system fault; therefore, operation during these periods is crucial to personnel safety, equipment damage

protection, and service reliability. The use of high-voltage protection aims to minimize the impact of

GPR and induced voltages. Varying methods of protection are being used today. IEEE Std. 487-1992

states, “Readers of this standard should evaluate all alternative procedures, methods, voltage limits, and

equipment characteristics for their own use.” Section 6.0, Protection Apparatus, describes broad

characteristics and application techniques of the current equipment in use today. The most common

equipment used in wire-line protection ranges from carbon blocks, spark gaps, and gas-filled and solidstate protectors to the more advanced relays, filters, neutralizing transformers and reactors, isolating

transformers, and the more recent use of optical couplers.

Section 8.0 of IEEE Std. 487-1992, Protection Theory and Philosophy, covers the different design and

philosophical approaches the telecommunications protection engineer and the power protective relaying

engineer may take in protecting telecommunications equipment. Section 8.2 of the standard covers

design requirements for wire-line facilities serving power stations. Information on many factors is needed

to properly design a protection scheme. A few of these conditions are:

1. Total available single-phase-to-ground fault current and its distribution, maximum GPR (rms),

X/R ratio, fault-produced longitudinal induction, lightning exposure

2. Power station ground grid impedance to remote earth and grid area

3. The extent of the GPR zone of influence

4. Whether the transmission parameters and service performance objectives are compatible with

the available or proposed facilities

5. Anticipated future changes in any of the above data

6. Whether lightning protection is required

Utilizing IEEE Std. 487-1992 is highly recommended for properly designing a protection system scheme.

The system designs and protection concepts contained in this standard have been mutually agreed to by

the power and telephone industries.

Wire lines entering substation premises have to have special protection against induced currents and rise

in station ground potential.

17.3.6.1 Voice and Data Channels: These circuits may use carbon blocks or similar devices that will

remove the circuit from service when they operate.

Voice traffic in most areas can be handled over wire lines since occasional interruptions can be tolerated

in voice and data transmission. Relaying can be performed over wire lines only if the responsible

telephone company can be relied on to provide circuits that are adequately protected against the effects of

nearby power system disturbances.

17.3.6.2 Relaying Channels: These circuits have to remain in service during and after a power

system fault. For audio tone circuits, fiber-optic isolators, high-voltage insulating transformers, gas tubes
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with mutual drainage reactors, and possibly neutralizing transformers may be required. Pilot-wire circuits

require neutralizing transformers whenever dc monitoring is used.

17.3.7 Satellite Communications

17.3.7.1 VSAT: Very small aperture terminals (VSATs) have been widely and successfully used for

SCADA master station-to-RTU communications. VSAT networks optimized for SCADA are offered by

network providers that sell the fixed transceiver equipment to the end user and then lease satellite airtime

(space segment) on a monthly basis. Monthly charges are based on the amount of data that is actually

transmitted by each VSAT. SCADA VSATs are most commonly used by electric utilities and pipeline

companies that have to communicate with RTUs over very large areas where leased telephone line and

private communication network costs are prohibitive. Electric cooperatives are probably the largest users

of satellite communications in the electric utility industry today.

Since the VSAT space segment is leased, and therefore entails recurring monthly costs, VSATs are

generally regarded as an alternative to leased telephone lines. VSATs do offer certain advantages over

leased lines, insofar as they are not prone to outage resulting from wind, ice, or lightning. Since VSATs

are wireless, they do not require high-voltage isolation as do leased telephone lines entering substations.

VSATs can experience path outages during extremely heavy rainfall. VSATs also suffer outages around

the spring and fall equinoxes, although these times are predictable and total equinox outage time is

generally only 1 to 2 hours per year.

VSAT network vendors also offer advanced network management services that are not available for

leased telephone lines. Since all signals pass through the vendor’s hub facility, the vendor can carefully

monitor channel performance and make maintenance adjustments when necessary.

Each message transmission between a master station and an RTU has to make two round trips to the

geostationary satellite via the vendor’s hub. Since each round trip requires at least 0.239 seconds to

complete, the space segment delay for a single message is approximately 0.5 seconds. For this reason,

inefficient SCADA master station-to-RTU communication protocols can result in the introduction of

considerable communications delays.

VSATs should only be employed for data applications such as SCADA, and where relatively long time

delays can be tolerated. VSATs are not considered suitable for voice or protective relaying applications.

In the early 1990s the Rural Electric Research (RER) Program of the National Rural Electric Cooperative

Association (NRECA) initiated a project with the Electric Power Research Institute (EPRI) to develop a

cost-effective Utility Communications Architecture-compliant satellite technology for rural utility

substations.

The project was developed by Nova-Net Communications, Inc., now an ICG Wireless Services Company.

The results of this project are documented in the final report of Project 91-10, “Bi-Directional Satellite

Communications Technology for Rural Utility Substations.”

Figure 17-9 shows a typical Nova-Net VSAT installation in a rural substation.
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Figure 17-9: VSAT Installed in Electric Substation. Courtesy of Nova Net, Inc.
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17.4 REFERENCES

ANSI/IEEE Std. 802.3, “Information Technology—Telecommunications and Information Exchange

between Systems—Local and Metropolitan Area Networks—Specific Requirements—Part 3:

Carrier Sense Multiple Access with Collision Detection (CSMA/CD) Access Method and

Physical Layer Specifications.”

ANSI/IEEE Std. 802.3v, “Information Technology—Local and Metropolitan Area Networks—Part 3:

Carrier Sense multiple Access with Collision Detection (CSMA/CD) Access Method and

Physical Layer Specifications, Informative Annex for Support of 150 ohm Cables in 10 BASE-T

Link Segment.”

ANSI/TIA/EIA- 232 E, “Interface Between Data Terminal Equipment and Data Circuit-Terminating

Equipment Employing Serial Binary Data Interchange.”

ANSI/TIA/EIA- 310-D, “Racks, Panels, and Associated Equipment.”

ANSI/TIA/EIA-422, “Electrical Characteristics of Balanced Voltage Digital Interface Circuits.”

ANSI/TIA/EIA-568-A, “Commercial Building Telecommunication Wiring Standard.”

BELLCORE/GR-253-CORE, “Synchronous Optical Network (SONET) Transport Systems: Common

Generic Criteria.”

BELLCORE/GR-1230-CORE, “SONET Bi-directional Line-Switched Ring Equipment Generic Criteria.”

BELLCORE/GR-1400-CORE, “SONET Dual Fed Unidirectional Path Switch Ring (UPSR) Equipment

Generic Criteria.”

BELLCORE/TR-TSY-000191, “Alarm Indication Signals Requirements and Objectives.”

General Electric, “GE Protection and Controls Relaying Communication Channels Application Guide,”

GET-8034, Malvern, Pa.: General Electric, 1993.

IEEE Std. 487, “IEEE Recommended Practice for the Protection of Wire Line Communication Facilities

Serving Electric Power Stations.”

ITU-R/RECMN V.35, “Data Transmission Using 60-108 kHz Group Band Circuits—Data

Communication Over the Telephone Network.”

Miriam, Bob, P. Sanders, and Roger E. Ray, “Power Line Carrier Channel & Application Considerations

for Transmission Line Relaying.” PULSAR/C045-P0597, Coral Springs, Fla.: Pulsar

Technologies, 1997.

NRECA/CRN “Bi-Directional Satellite Communications for Rural Utility Substations,” Project 91-10,

December 1995.
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APPENDIX I TO CHAPTER 17

GLOSSARY OF TERMS

All-Dielectric Self-Supporting (ADSS): ADSS cables are self-supported, requiring no support

messenger. The cables are all dielectric (containing no metals), so they can be safely installed in the

supply space on electric utility poles.

Asynchronous Transfer Mode (ATM): A communications transmission and switching standard for

carrying broadband signals at speeds of up to 2.2 gigabits per second. Combines techniques of time

division multiplexing and packet switching.

Basic Impulse Insulation Level (BIL): A rating level to determine how insulating materials react to

impulse voltages. As BIL increases, so does the amount of insulation required to protect the equipment.

DS1: Digital Signal Level 1; the designation given to a digital hierarchy of circuits or channels operating

at 1.544 Mbps; commonly referred to as T1.

EHV: Extra high voltage; usually ranges from 345 kV to 765 kV.

Federal Communications Commission (FCC): A board of commissioners appointed by the President

who have the power to regulate non-federal communications systems.

Frequency Shift Keying (FSK): Modulation type used in short-distance wire-line communications.

Ground Potential Rise (GPR): A phenomenon that occurs when there is a high-voltage difference

between a grounded communications site and a distant site connected by wire-line communication

circuits that has the potential to damage communication equipment.

Intelligent Electronic Devices (IEDs): Electronic equipment that provides monitoring and controlling

capabilities.

kHz: Kilohertz; one thousand cycles per second.

Line Tuner Unit (LTU): A tuning network used to match the transmitter output impedance with the

impedance seen at the coupling capacitor input.

Multiple/Address System (MAS): Radio system using master–slave protocol to communicate to a

minimum of four remote computers.

MHz: Megahertz; one million cycles per second.

OC-1: SONET optical carrier 1, operating at data rate of 51.84 Mbps.

OC-3: SONET optical carrier 3, operating at data rate of 155.52 Mbps.

Optical Ground Wire (OPGW): Optical fibers (numbering typically from 6 to 48 fibers) placed inside

a specialized conductor that serves as both a fiber-optic communications facility and a ground wire or

shield wire.
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Pulse Code Modulation (PCM): A scheme of transmitting data by digitizing and then using pulse codes

to transmit the digitized data.

Remote Terminal Unit (RTU): An electronic device used to control and monitor Input/Output points,

within an overall system and to communicate the derived data to a master station or other “host” unit.

SCADA: Supervisory Control and Data Acquisition; used by utilities and other process-oriented

operations to collect data from machinery that may be spread over a very large geographic area. A basic

SCADA system consists of two types of devices: master and remote. The master resides at a centrally

manned location while the remotes are generally placed at unmanned locations. Communication between

master and a number of remotes can be via telephone-like circuit, radio channels, or fiber-optic

communications media.

SONET: Synchronous Optical Network; standard for optical transport formulated by the Exchange

Carrier Standards Association (ESCA) for ANSI; essentially a standard for Broadband Integrated Services

Digital Network transmission facilities.

Time-Division Multiplexing (TDM): A method of transmitting several signals on a single line on a

time-sharing basis.
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CHAPTER 18

INSPECTION

18.1 PURPOSE

Guidelines for the required inspection procedures for substation equipment, structures, and other devices

discussed in this chapter are necessarily general. They have to be tailored to meet the requirements of a

specific site as well as for the equipment at this site.

For additional information and references, see International Electrical Testing Association (NETA)

Acceptance Testing Specifications and Maintenance Testing Specifications for Electrical Power

Distribution Equipment and Systems.

In all cases, specific equipment manufacturers’ recommendations, as contained in the equipment

instruction books, should be observed and factored into the procedure as outlined. All inspections and

tests should also be performed in accordance with applicable codes and standards including those of the

NEC, ANSI, IEEE, NFPA, NEMA, and OSHA.

Perform certain test and maintenance procedures as the inspections are made. Therefore, coordinate the

recommendations with those contained in the chapters covering testing (Chapter 19) and maintenance

(Chapter 20).

18.2 GENERAL

It is essential that inspections of substation equipment, structures, and other devices be made periodically.

In addition to this periodic inspection, other inspections may be required to ascertain the cause of

particular problems, when equipment is placed in service, or when the substation, or portions thereof, are

taken out of service.

18.2.1 Records

Maintain a record system for each substation site. This record system should at least provide the

following information.

18.2.1.1 Equipment Records: These include equipment nameplate data together with specific

transformer or voltage regulator tap connection details, trip settings, etc., for all equipment.

18.2.1.2 Inspection Records: These records, when accurately maintained, permit evaluation of the

serviceability of equipment to be made at any time.

18.2.1.3 Inspection Checklist: This list, derived for a specific substation, contains all items to be

inspected during periodic inspections.

18.2.2 Safety

So that all inspection procedures may be fulfilled safely and properly, it is essential that all personnel be

thoroughly trained in proper and safe procedures. This includes but is not limited to the following:
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1. Familiarity with operating procedures for the substation.

2. Familiarity with the applicable safety rules and regulations such as, but not limited to, the

following:

a. ANSI C2, National Electrical Safety Code

b. OSHA 29 CFR 1910, Subpart S, Electrical Safety Related Work Practices

c. OSHA 29 CFR 1910.269, Electric Power Generation, Transmission and Distribution

d. OSHA 29 CFR 1910.137, Electrical Protective Equipment

e. OSHA 29 CFR 1926, Subpart K, Electrical Safety Related Work Practices

f. Applicable state and local safety operating procedures

g. The cooperative’s safety practices

3. Familiarity with protective and interlocking schemes.

4. Knowledge of the capabilities of the equipment.

5. The proper use of safety equipment.

6. The knowledge and proper use of first aid procedures and equipment.

7. The knowledge and proper use of equipment grounding techniques.

8. The prompt repair of any defects or improper conditions as soon as possible after they are

noted.

9. Observation of safety regulations at all times. Proper distances have to be maintained from

energized equipment. See the following standards as guidelines for the minimum clearance

distances that have to be maintained between personnel and energized equipment:

a. ANSI C2, NESC, Sections 43-44

b. OSHA 29 CFR 1910.333, Selection and Use of Work Practices

10. Use of proper safeguards such as danger signs, temporary barriers, etc., for the safety of

persons close to, but not engaged, in the work to be performed.

18.3 PERIODIC INSPECTIONS

The substation in total and the individual items of equipment contained therein should be periodically

inspected. The recommended frequency of these inspections is as follows:

1. Visual inspection of total substation - monthly

2. Inspection with diagnostic online test equipment - annually

3. Detailed inspection of major equipment - annually

4. Internal inspection of transformers and regulators – as required

The recommended frequency may be varied if the cooperative has a reliability-centered maintenance

program in place. See Chapter 20 for further information.
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18.3.1 Visual Inspections

Visual inspections should encompass the total substation area including the site, the control house, and all

equipment and structures. Make this inspection with the substation energized. Therefore, make all

inspections from ground level to ensure adequate safety clearances from energized parts. Use binoculars

to view buses and other equipment located on structures.

Use special care when ground connections are checked, since a high voltage could develop across any gap

created between a ground cable and a piece of equipment, particularly under fault conditions. For this

reason, do not remove ground connections for any reason while the substation is energized.

The following describes details of visual inspection.

18.3.1.1 Power Transformers

1. Inspect the control cabinet, control relays, contactors, indicators, and the operating

mechanism.

2. Look for loose, contaminated, or damaged bushings; loose terminals; and oil leaks.

3. Check oil levels in main tanks, tap changer compartment, and bushings.

4. Inspect the inert gas system (when applicable) for leakage, proper pressure, etc.

5. Read and record the operations counter indicator reading associated with the load tap changer.

6. Observe oil temperature. Oil temperature should not exceed the sum of the maximum winding

temperature as stated on the nameplate plus the ambient temperature (not to exceed 40°C) plus

10°C. Generally, oil temperature does not exceed 95° and 105°C for 55° and 65°C winding

temperature rise units, respectively, since the ambient temperature rarely exceeds 30°C for

periods long enough to cause an oil temperature rise above these points.

18.3.1.2 Voltage Regulators

1. Perform the same inspections as listed for power transformers (as applicable).

2. Place the regulator control in the manual position and operate the regulator over a small range

only.

3. Return the control to automatic and verify that the regulator operates to return the output

voltage to normal.

4. Read and record the operations counter indicator reading.

18.3.1.3 Oil, Vacuum, SF6 and Air Blast Circuit Breakers

1. Check for loose, contaminated, or damaged bushings; loose terminals; oil leaks; and proper

gas pressures.
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2. Check the oil level in bushings and the main tank (if applicable).

3. Check the anti-condensation heaters.

4. Read and record the number of operations indicated. If the breaker has not operated during

the preceding year, bypass the breaker or otherwise take it out of the circuit for testing. Test

the breaker by simulating relay action by placing a jumper across the tripping contact studs on

the back of the relay. Allow the breaker to go through its sequence to check its operation.

5. Inspect contact areas on the main plug-in assembly for signs of overheating or arcing.

6. Read and record compressor operating hours as shown on the indicator.

18.3.1.4 Fuses

1. Observe the condition of the contact surface of fuse clips.

2. Check for broken or cracked supporting insulators and for contamination.

18.3.1.5 Surge Arresters

1. Check for cracked, contaminated, or broken porcelain; loose connections to line or ground

terminals; and corrosion on the cap or base.

2. Check for pitted or blackened exhaust parts or other evidence of pressure relief.

3. If discharge counters are provided, check connections and record the number of operations.

18.3.1.6 Buses and Shield Wire

1. Inspect bus supports for damaged porcelain and loose bolts, clamps, or connections.

2. Observe the condition of flexible buses and shield wires.

3. Inspect suspension insulators for damaged porcelain (include line entrances).

18.3.1.7 Capacitors (Series and Shunt)

1. Observe the condition of fuses.

2. Inspect for damaged tanks and bushings and for leakage of the dielectric.

18.3.1.8 Reactors (Oil Filled and Air Core)

1. Observe the condition of paint and varnish.

2. Inspect bushings for cracks and contamination.

3. Check valves and gaskets for oil leaks (if applicable).
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18.3.1.9 Disconnects and Other Switches

1. Check for cracked, contaminated, or broken porcelain; loose connections; and corrosion to

metal parts.

2. Observe the condition of contact surfaces and the area around them.

3. Observe the condition of arcing horns on air break switches (when applicable).

4. Inspect the operating mechanism.

5. Inspect all live parts for scarring, gouging, or sharp points that could contribute to radio noise

or corona.

6. Inspect flexible braids or slip-ring contacts used for grounding for corrosion wear or broken

strands.

7. Check gearboxes for signs of moisture or corrosion.

8. Check corona balls and rings for damage.

18.3.1.10 Control and Metering Equipment

1. Check current and potential transformers for damage to cases, bushings, terminals, and fuses.

Verify the integrity of the connections, both primary and secondary.

2. Observe the condition of control, transfer, and other switch contacts; indicating lamps; test

blocks; and other devices located in or on control cabinets, panels, switchgear, etc. Look for

signs of condensation in these locations.

3. Examine meters and instruments externally to check for loose connections and damage to

cases and covers. Note whether the instruments are reading or registering.

4. Open and close each potential switch on the test block to determine whether the speed of the

meter disk is affected. Repeat the process with the current switches. Changes of speed should

be approximately the same for each meter element.

5. Check the status of relay targets (where applicable).

6. Make an external examination of relays, looking for damaged cases and covers or loose

connections.

7. Check the station battery for loose connections and battery cells for low level or low specific

gravity of the electrolyte. Record the electrolyte temperature.

8. Inspect the station battery charger. Check the charging current and voltage. Observe the

ground detector lamps for an indication of an undesirable ground on the dc system.

9. Check the annunciator panel lights.
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18.3.1.11 Structures

1. Inspect all structures for loose or missing bolts and nuts.

2. Observe any damaged paint for galvanizing or signs of corrosion.

3. Inspect for deterioration, buckling, and cracking.

18.3.1.12 Grounding System

1. Check all above-grade ground connections at equipment, structures, fences, etc.

2. Observe the condition of any flexible braid type connections.

18.3.1.13 Cable

1. Inspect exposed sections of cable for physical damage.

2. Inspect the insulation or jacket for signs of deterioration.

3. Check for cable displacement or movement.

4. Check for loose connections.

5. Inspect shield grounding (where applicable), cable support, and termination.

18.3.1.14 Foundations

1. Inspect for signs of settlement, cracks, spalling, honeycombing, exposed reinforcing steel, and

anchor bolt corrosion.

18.3.1.15 Substation Area (General)

1. Verify the existence of appropriate danger and informational warning signs.

2. Check indoor and outdoor lighting systems for burned-out lamps or other component failures.

3. Verify that there is an adequate supply of spare parts and fuses.

4. Observe the condition of hook sticks.

5. Inspect the fire protection system and the provisions for drainage in the event of leaking oil.

6. Check for bird nests or other foreign materials in the vicinity of energized equipment, buses,

or fans.

7. Observe the general condition of the substation yard, noting the overall cleanliness and the

existence of low spots that may have developed.
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8. Observe the position of all circuit breakers in the auxiliary power system and verify the

correctness of this position.

9. Inspect the area for weed growth, trash, and unauthorized equipment storage. . (See ANSI C2,

NESC Rule 110B2 for information regarding storage).

18.3.1.16 Substation Fence

1. Check for minimal gap under the fence or under the gate. A reasonable rule of thumb would

be less than 2 inches under the fence and 4 inches under the gate.

2. Ensure the fence fabric is intact and there is no rust.

3. Check that the barbed wire is taut.

4. Ensure the gate latches are operable.

5. Ensure flexible braid-type connections are intact.

6. Verify that no wire fences are tied directly to the substation fence.

18.3.2 Inspection With Diagnostic Online Test Equipment

Consider supplementing the visual inspections with the periodic use of diagnostic test equipment that

allows more detailed inspection of the equipment while it is still energized. Some of these techniques are

described below. Table 18-1, Substation Equipment Inspection Technology Matrix, lists equipment and

what inspection technologies may be of value in identifying the condition of the equipment.

18.3.2.1 Infrared Thermography: Infrared thermography can provide a non-contact means of online

evaluation of “hot spots” in an energized system. The infrared viewer provides a television-like image of

the natural infrared energy being emitted from the objects in its field of view. The pictures, commonly

referred to as thermograms, can be analyzed in real time or stored electronically and analyzed in the office

or lab. When a loose or corrosive connection is present under loaded conditions, the infrared viewer can

detect the temperature differential between the connection and the surrounding conductors.

When doing infrared scanning, the following test parameters need to be taken into account:

1. Infrared scanning surveys should be done during periods of maximum possible loading, but

not less than 40 percent of rated load of the electrical equipment being inspected. Refer to

NFPA 70B, Section 18-16, Infrared Inspection.

2. Inspect distribution systems with imaging equipment capable of detecting a minimum

temperature difference of 1°C at 30°C.

A general outline for a thermographic survey follows.
Bulletin 1724E-300

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Table 18-1: Substation Inspection Technology Matrix

Component Description Infrared

Therm.

Lab Oil

Analysis

Ultrasonic

Flow

Vibration UltrasoundRecording

Temp. Surveys

On-Site Oil

Analysis

Visual

Generator Step-Up Transformer X X X X X X X X

Transmission Transformer X X X X X X X X

Step-Down Dist. Transformer X X X X X X X X

Current Transformer X X X

Potential Transformer X X X

Trans. Blower Motors X X X X X

Trans. Oil Pumps X X X X X

Trans. Coolers X X

Trans. Tap Changers X X X

Trans. Control Cabinets X X

Oil Circuit Breakers X X X X

Air Circuit Breakers X X X

S.F.6 Breakers

DC Control Batteries X

Trans. & Dist. Bus X X X

Disconnects X X X

Enclosed Switchgear X X X

Ground Networks X X

Dist. Regulators X X X X X

Light & Power Trans. X X

D.C. Control Bus X X

Fuse & Fuse Clip X X

Terminal Blocks X X

Enclosed Buswork X X

Cable Splices X X X

Reactors X X X

Compressor Motors X X X X

Nitrogen Systems X

Motors X X X X

Lightning Arrestors X X X

Carrier Current Wave Traps X X X

Insulators X X X

Batteries X X
Bulletin 1724E-300

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THERMOGRAPHIC SURVEY

1. Inspection and Preparation of Equipment To Be Surveyed

a. Inspection of physical, electrical, and mechanical condition of equipment

b. Where applicable, removal of all necessary covers prior to thermographic inspection

2. Report Components

a. Load conditions at the time of the inspection

b. Hot spots

c. Temperature difference between the area of concern (hot spot) and the reference area

d. Cause of temperature difference

e. Areas inspected, with inaccessible and / or unobservable areas and /or equipment

identified

f. Photographs and/or thermograms of the hot spot area

3. Test Results

a. Temperature differences of 1°C to 2°C that indicate possible deficiency and warrant

investigation

b. Temperature differences of 4°C to 15°C that indicate deficiency and has to be repaired as

time permits

c. Temperature differences of 16°C and above that indicate major deficiency and has to be

repaired immediately

18.3.2.2 Laboratory Oil Analysis: All oil-filled power transformers and circuit breakers generate

gases during normal operation. But when the equipment begins to function abnormally, the rate of gas

production increases. Analyzing these gases and their rate of production is another valuable tool for

evaluating the condition of an operating transformer or breaker. Other tests can also be performed on the

oil to determine the oil’s condition. For additional information on oil analysis, see Chapter 19 of IEEE

Std. C57.106, “Guide for Acceptance and Maintenance of Insulating Oil in Equipment.”

18.3.2.3 Ultrasound: Another method for evaluating a system that is energized is the use of an

ultrasound detector. Ultrasound is used to detect inaudible noises on equipment that could indicate

potential problems. Listed below are some examples of what ultrasound can be used to detect.

1. Bus: When corona is present in medium- and high-voltage circuits, air is ionized. Corona

emits a high-frequency pitch that can be heard with the human ear. However, the ultrasound

detector can pinpoint low levels or corona not heard by the human ear and also at greater

distances. Substations and transmission lines can be audibly inspected by this method to

locate sources of corona. The ionized air generated by corona will attack insulation. The early

detection of its presence can allow for corrective measures before further insulation

deterioration occurs.

2. Power Transformers: Ultrasound can detect inaudible noises on transformer internals that

could indicate arcing, sparking, partial discharge, combustible gases, corona, core looseness,

vibration, or loose parts.

3. Cooling Pumps and Fan Motors: Ultrasound can also be used to evaluate the overall

condition, and for cavitation and flow.
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18.3.2.4 Portable Gas in Oil Analysis: This analysis measures the amount of dissolved combustive

gases in transformer oil and/or hot metal gases in tap changer oil, which can be the evidence of arcing,

sparking, partial discharge, corona, and/or overheating. This can be done in the field and can be used for

trending and historical information. If there is a noticeable increase in the amount of dissolved

combustive gases, a laboratory oil analysis should be done to determine the cause of the increase. See

Chapter 19 for additional information on testing.

18.3.3 Detailed Inspection of Major Equipment

Annual inspections are recommended for certain major equipment and portions of the auxiliary system.

These inspections are detailed and will therefore require that the piece of equipment being inspected be

de-energized.

Annual inspections are recommended for the following equipment:

1. Disconnects and other switches

2. Metal-clad switchgear

3. Air circuit breakers

4. Oil circuit breakers

5. Air blast and SF6 circuit breakers

6. Vacuum circuit breakers

The annual inspections should be conducted simultaneously with and in addition to the bi-monthly

inspections suggested in Section 18.3. Details are described in the following sections.

18.3.3.1 Disconnects and Other Switches

1. Inspect moving and fixed contacts. Verify the adequacy of the wiping action. Check contact

pressures.

2. Inspect the spring assembly for signs of corrosion (air break switches only) and tighten bolts.

3. Inspect the current shunt around the spring assembly and tighten all bolts.

4. Check the fluid levels in gearboxes (where applicable).

5. Check the blade alignment on gang-operated switches.

6. Inspect the switch base and other galvanized parts for signs of corrosion.

7. Verify the correct operation and adjustment of motor-operated limiting switches and

mechanical interlocks (where applicable).

8. Perform a contact resistance test and compare it with the manufacturer’s acceptable resistance

values.
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18.3.3.2 Metal-Clad Switchgear

1. Inspect for damage to enclosures, doors, latching mechanisms, etc.

2. Inspect bus supports for signs of cracking.

3. Verify that all joints are tight.

4. Check the alignment of all disconnect devices, both primary and secondary, including those

for potential transformers.

5. Inspect terminal connections and the condition of wiring.

6. Check rails, guides, rollers, and the shutter mechanism.

7. Inspect cell interlocks, cell switches, and auxiliary contacts.

8. Inspect control, instrument, and transfer switches.

9. Inspect for broken instrument and relay cases, cover glass, etc, and check for burned-out

indicating lamps.

18.3.3.3 Air Circuit Breakers (15 kV and Below)

1. Inspect contacts for visual signs of overheating. Check contact clearance, contact wipe,

toggles, latches, position indicator, auxiliary contacts, etc.

2. Inspect hardware and check wire connections for secureness.

3. Inspect arc interruption chambers.

4. Inspect relay contacts.

5. Check fuse clips for secureness.

6. Check the condition of bushings, porcelains, and contact surfaces.

7. Check the load conductor terminations.

8. Check the current transformer connections.

9. Check the grounding connections.

10. Check the lifting or racking mechanism (if applicable).

18.3.3.4 Oil Circuit Breakers

1. Check compressor operation, including operation of all pneumatic switches and their

operating set point.
Bulletin 1724E-300

Page 728

2. Check for air leaks.

3. Check the compressor belts.

4. Check the latching mechanisms, relay contacts, and fuse clips (for secureness).

5. Untank the breaker and check.

6. Check pole units, contacts, bayonets, interrupters, and resistors for signs of heating.

7. Inspect the hardware and wiring connections for CTs.

8. Inspect the alignment of contacts.

9. Inspect the operating mechanism and leakage.

10. Inspect the lift rod and toggle assembly.

NOTE: Untanking is required only when specified in the manufacturer’s instruction book. This is

normally done after a trip operation when the magnitude of current interrupted approaches the maximum

capability of the breaker or after a particular number of operations. In the latter case, the time of

inspection should be coordinated with the annual inspection whenever possible.

CAUTION: Observe the manufacturer’s recommendations with respect to manual operation of the

circuit breaker without oil.

18.3.3.5 Air Blast and SF6 Circuit Breakers

1. Perform all checks and inspections as outlined in Section 18.3.3.4 for oil circuit breakers.

2. Inspect the compressor system, including belts, pneumatic switches, contactors, relays, and

other auxiliary devices.

3. Inspect the gas or air piping for signs of deterioration.

4. Inspect all air or gas seals and o-rings.

5. Inspect the wiring connections and hardware for CTs.

18.3.3.6 Vacuum Circuit Breakers

Perform all checks and inspections as outlined in Section 18.3.3.3 for air circuit breakers except for all

reference to inspection of main contacts or arc interruption chamber.

18.3.4 Internal Inspection of Transformers and Regulators

Internal inspections require considerable time out of service for the equipment involved. Therefore, they

should be scheduled, whenever possible, to coincide with planned substation outages.
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Since large equipment is frequently required for use in disassembly operations, it is essential that all

aforementioned safety precautions be rigidly followed. Details of these inspections follow.

18.3.4.1 Transformers: Open-type transformers (those that may breathe free air) that have not been

so inspected for at least three years should, if time permits, be given an internal inspection consisting of

the following:

1. Lower the oil level to expose the top of the core coil assembly.

2. Look for evidence of corrosion of tank walls and other metal parts.

3. Check connections for secureness.

4. Check to see whether sludge deposits have accumulated in ducts or other locations. Such

deposits impede the circulation of oil and thus any appreciable amount should be removed.

5. Test samples of oil taken from the bottom of the tank to determine the water content. See

Chapter 19, Testing.

18.3.4.2 Regulators: Inspect voltage regulators using the same criteria as indicated for open

transformers. It may be necessary to untank the core and coil assembly to complete the inspection.

18.4 NON-PERIODIC INSPECTIONS

Whenever a substation, or any part of it, is de-energized for any reason, a detailed inspection should be

made of those items of equipment that cannot be observed at close range when energized. In particular,

this includes:

1. Transformers

2. Regulators

3. Fuses

4. Disconnects

5. Air Break Switches

6. Load Interrupter Switches

7. Grounding System

8. Circuit Breakers

9. Oil Circuit Breakers

10. Structures

11. Buses

The extent of the inspections may be limited because of the time available during the period of deenergization. However, it is essential to perform as many items as possible. Details of the inspection

procedures are outlined in the following sections.

18.4.1 Inspection of Porcelain

Inspect all insulators and equipment bushings for chipped petticoats and fractured or cracked porcelain.

Flashovers in the past may have damaged a portion of the glazing on the porcelain. Make this inspection

at close range.
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18.4.2 Fuses, Disconnects, and Other Switches

Inspect current-carrying portions to verify that proper tensions are being maintained. Inspect contact

surfaces for pitting, burning, alignment, and pressure. Replace badly pitted or burned contacts. See that

all bolts, nuts, washers, pins, and terminal connectors are in place and in good condition.

18.4.3 Buses

Inspect all bus fittings, connectors, couplers, etc., to verify that all bolts are tight and that there is no

indication of hot spots, as evidenced by discoloration. Also verify the integrity of the stranding of

flexible buses at strain clamps.

18.4.4 Transformers

Check open transformers that have not been internally inspected for at least three years in accordance

with details contained in Section 18.3.4, Internal Inspection of Transformers and Regulators.

18.4.5 Transformer On-Load Tap Changers

If the number of operations of the tap changer contactor is approaching mandatory inspection and

possible replacement of the contacts in accordance with the manufacturer’s recommendations, this

inspection might best be performed at this time. In this case, the tap changer compartment has to be

drained of oil. Inspect all portions of the mechanism for excessive wear and proper adjustment.

18.4.6 Regulators

Check voltage regulators that have not been internally inspected for at least three years in accordance with

details contained in Section 18.3.4, Internal Inspection of Transformers and Regulators.

18.4.7 Oil Circuit Reclosers

Inspect these devices in accordance with the instructions in 7 CFR 1730, “Electric System Operation and

Maintenance,” and RUS Bulletin 1730-1, “Electric System Operation and Maintenance (O&M).”

18.4.8 Circuit Breakers

Inspect circuit breakers in accordance with the applicable procedures contained in Section 18.3.3 if they

have not been so inspected within the previous 12 months.

18.4.9 Grounding System

Check all accessible ground connections for secureness, and measure the overall ground grid resistance if

it has not been done for a number of years. Since it is desirable to disconnect shield wire grounds and

system neutral connections to make this measurement, the total substation has to be de-energized for these

tests. See Chapter 19, Tests, for details.

18.4.10 Structures

Inspect all structures in close proximity to buses, energized portions of equipment, etc., and make
Bulletin 1724E-300

Page 731

necessary repairs to galvanizing and painted surfaces. See Chapter 20, Maintenance, for details.

18.5 REFERENCES

7 CFR 1730, “Electric System Operation and Maintenance.”

ANSI Std. C2, National Electrical Safety Code (NESC).

IEEE Std. C57.106, “Guide for Acceptance and Maintenance of Insulating Oil in Equipment.”

International Electrical Testing Association (NETA), Acceptance Testing Specifications for Electrical

Power Distribution Equipment and Systems, 1999.

International Electrical Testing Association (NETA), Maintenance Testing Specifications for Electrical

Power Distribution Equipment and Systems, 1997.

NFPA 70B, Section 18-16, “Infrared Inspection.”

OSHA 29 CFR 1910, “Subpart S Electrical Related Work Practices.”

OSHA 29 CFR 1910.137, “Electrical Protective Equipment.”

OSHA 29 CFR 1910.269, “Electrical Power Generation, Transmission and Distribution.”

OSHA 29 CFR 1926, “Safety and Health Regulations for Construction.”

OSHA 29 CFR 1910.333, “Selection and Use of Work Practices.”

RUS Bulletin 1730-1, “Electric System Operation and Maintenance (O&M).”
Bulletin 1724E-300

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(BLANK PAGE)
Bulletin 1724E-300

Page 733

CHAPTER 19

TESTS

19.1 GENERAL

Tests of substation equipment are required to fulfill at least the following functions:

a. To prove the integrity of a piece of equipment at the time of acceptance

b. At periodic intervals, to verify the continued availability of the equipment

c. At the time of failure of a piece of equipment, to be able to determine the specific

requirements for repair

The types of tests to be performed for each of the above categories vary. Guidelines are therefore

included to assist in this selection. The guidelines are, of necessity, quite general in nature and, as such,

have to be tailored to meet the requirements of the specific equipment.

Coordinate the testing schedules with the inspections as detailed in Chapter 18. In addition, utilize

scheduled outages to the greatest extent possible as periods for testing since certain equipment is

unavailable for test unless large portions of the substation are de-energized.

Upon completion of tests, make provisions to follow-up with repeat tests where required and make repairs

where the need is indicated by the test results.

In all cases, factor into the testing procedures outlined specific equipment manufacturer’s recommendations as contained in the equipment instruction books.

19.1.1 Records

Maintain a records system, as outlined in Chapter 18, Inspection, for each site. In addition to the details

contained therein, these records should contain at least the following information:

a. The name, date, and results of all tests performed

b. The date when the equipment should again be tested

c. Any requirements for follow-up or special tests required as a result of indications of potential

trouble

19.1.2 Safety

Some tests, particularly those requiring gas or oil samples, may be performed without removing the

equipment from service. The personnel performing such tests or obtaining gas or oil samples have to

observe safety regulations at all times. Special attention is called to the minimum clearances provided in

Chapter 18. Whenever possible, provide temporary barriers to isolate the equipment being tested from

adjacent energized equipment.

Testing equipment is usually very specialized. Restrict its use, therefore, to those personnel who have

been adequately trained. Improper use of the equipment may expose both the user and the equipment to

hazards.
Bulletin 1724E-300

Page 734

The analysis of properly obtained test data is again a specialized technique. Failure to recognize trends

while conducting a test could be injurious to the personnel, the test equipment, and the equipment being

tested. Failure to recognize trends in data obtained at different times can result in the failure to detect

potential problems in sufficient time to permit an orderly and timely removal of equipment from service.

19.2 DETAILED REQUIREMENTS

As indicated above, testing is performed to accomplish three distinct functions: the acceptance of

equipment, the periodic verification of its integrity, and to permit better analyses of its failure.

19.2.1 Acceptance Tests

Acceptance tests are performed after receipt and erection or installation of equipment at a site. The

results of these tests are compared with the specifications, where applicable, evaluated, and compared

with acceptable norms and factory test data and, when found acceptable, recorded for future reference.

The recommended acceptance tests, delineated by type of equipment, are indicated in Table 19-l.

19.2.2 Periodic Tests

Periodic tests, those used to establish the continuing quality of the equipment, are conducted at varying

intervals, depending on the type of equipment. Table 19-2 provides a tabulation of the recommended

periodically conducted tests together with the recommended interval between tests.

19.2.3 Tests After Failure

Testing conducted after an equipment failure is performed to determine, to the greatest extent possible,

the location, magnitude, and cause of the failure. Such data, when properly obtained, is used in

determining whether the equipment can be repaired in place or needs to be shipped to a repair shop. The

tests to be performed in such cases are the same as listed in Table 19-2, except that high-voltage tests are

not usually performed.

19.3 DESCRIPTION OF TESTS

Descriptions of the tests indicated in Tables 19-l and 19-2 are contained in subsequent paragraphs

together with ranges of test values that are considered acceptable.

Specific details for application of the test equipment are in the instruction book for that item of test

equipment. A brief reference to applicable test equipment is also included with the description of each

test. The ranges and outputs indicated are considered appropriate for the tests and thus should not be

varied significantly.

19.3.1 Insulation Resistance Test

This test is performed to verify the integrity of the insulation as is used in all types of electrical

equipment. This includes transformers, circuit breakers, cables, motors, switches, etc.

19.3.1.1 Equipment Required: 500/1000/2500 volt “megger,” either motor driven or voltage

regulated.
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Page 735

Table 19-1: Acceptance Test Requirements

Required Tests

®

Items To Be Tested

 ̄

Insulation Resistance TestPower Factor TestDC High Potential TestDielectric Absorption TestAC Over-Potential TestWinding Resistance MeasurementInsulating Oil Dielectric StrengthInsulating Oil Power Factor TestTiming TestSeries Overcurrent TestTurns Ratio TestPolarity TestCapacitance TestPressure Test of Piping andReceiversGrid ResistanceVisual InspectionCore-to-Ground InsulationResistance Test

Transformer, Conservator Type X X X X X X X X X X

Transformer, Inert Gas Cushion Type X X X X X X X X X X

Load Tap Changer Mechanism X X X X

Regulators X X X X X X

Oil Circuit Breakers X X X X

Air Circuit Breakers X X X X

Vacuum Circuit Breakers X X X

SF6 Circuit Breakers X X X X

Air Blast Circuit Breakers X X X X

PTs X X X X X

CTs X X X X X

CCPDs X X X

Surge Arresters X X

Cable, 600 Volts X X X

Cable, 5 kV and Above X X X X X

Disconnects and Air Break Switches X X

Vacuum Switches X X X X

Circuit Switchers X X X

Capacitors X X

Metal-Clad Switchgear X X X X X X

Protective Relays X X X

Metering Equipment X X

Substation Ground Grid X X

Test Procedure or Details Outlined in Paragraph

19.3.119.3.219.3.319.3.419.3.519.3.719.3.819.3.819.3.1119.3.1319.3.1419.3.1519.3.1819.3.1919.3.2019.3.1
Bulletin 1724E-300

Page 736

Table 19-2: Periodic Test Requirements

Required Tests

®

Items To Be Tested

 ̄

Insulation Resistance TestPower Factor TestDC High Potential TestDielectric Absorption TestAC Over-Potential TestContact Resistance TestCalibration TestInsulating Oil NeutralizationNumberInsulating Oil Interfacial TensionInsulating Oil Dielectric StrengthInsulating Oil Color TestInsulating Oil Visual ExaminationInsulating Oil Power Factor TestInsulating Oil Combustible GasAnalysisSF6 Gas AnalysisTiming TestMotion Analyzer TestSeries Overcurrent TestTurns Ratio TestCapacitance TestGrid ResistanceVisual InspectionCore-to-Ground InsulationResistance Test

Transformer, Conservator Type 12 12 12 12 12 12 6 12 6 24 2 12

Transformer, Inert Gas Cushion Type 12 12 12 12 12 12 6 12 6 24 2 12

Load Tap Changer Mechanism 12 12 12 12 12 6 12 2

Regulators 12 12 12 12 12 12 6 12 2

Oil Circuit Breakers 12 12 12 12 12 12 6 12 12 12 2

Air Circuit Breakers 12 24 12 12 12 2

Vacuum Circuit Breakers 12 12 12 2

SF6 Circuit Breakers 12 12 12 12 2

Air Blast Circuit Breakers 12 12 12 2

PTs 12 2

CTs 12 2

CCPDs 12 12 2

Surge Arresters 12 2

Cable, 600 Volts 2

Cable, 5 kV and Above 12 12 12 2

Disconnects and Air Break Switches 12 12 2

Vacuum Switches 12 12 12 2

Circuit Switchers 12 12 2

Capacitors 12 2

Metal-Clad Switchgear 12 12 12 24 1

Protective Relays 24 12 1

Metering Equipment 12 1

Substation Ground Grid 1

Test Procedure or Details Outlined in

Paragraph

19.3.119.3.219.3.319.3.419.3.519.3.619.3.1719.3.819.3.819.3.819.3.819.3.819.3.819.3.919.3.1019.3.1119.3.1219.3.1319.3.1419.3.1819.3.2019.3.1

NOTE: The number in the box indicates the amount of time in calendar months between periodic tests.
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19.3.1.2 Typical Minimum Resistance Values

AC Motors, 75°C 120-volt - 1.12 megaohms

208-volt - 1.20 megaohms

240-volt - 1.25 megaohms

480-volt - 1.50 megaohms

DC Motors, 75°C All voltages - 1.00 megaohms

High-Voltage Circuit Breakers, 20°C 10,000 megaohms

High-Voltage Bushings, 20°C 10,000 megaohms

Insulated Cable - Varies as a function of type and thickness of insulation; see ICEA Standards

Transformers, Oil-Filled, 20°C

 Where:

E = Voltage rating of winding under test

kVA = Rated capacity of the winding under test

Transformers, Dry type, 20°C, where E and kVA are as defined above

Other Equipment - Refer to Manufacturer’s Data

19.3.2 Power Factor Test

This test is used to measure the power factor of the insulation in all types of electrical equipment and

cable. The test has to be conducted at temperatures above 0°C since ice is a relatively good conductor.

This test provides an indication of the quality of the insulation. Values obtained during the acceptance

tests are compared with expected ranges of values determined from similar equipment. After the initial

tests, comparison is made between values obtained at different times so as to establish a trend and thus

anticipate potential troubles. Whenever possible, incorporate power factor tests into the routine factory

tests for equipment. The acceptance test values may then be directly compared with the factory values.

19.3.2.1 Equipment Required: Test equipment, such as manufactured by the Doble Engineering

Company or Biddle Company, Inc., Hipotronics, and others, is among that suitable for this purpose.

19.3.2.2 Acceptable Values: Acceptable values of power factors for various items of equipment are

provided with the test equipment. Additionally, equipment manufacturers frequently provide this data for

their specific equipment. The values given in Table 19-3 for a few common items are provided for

reference only, so as to illustrate the very low magnitudes of power factors encountered.

19.3.3 DC High Potential Test

This is a test of the dielectric strength of insulation. It is used to determine the quality of the insulation in

electrical equipment, particularly for items with solid dielectrics such as porcelain, rubber, PVC, PE,

Micarta, etc. It is not generally used for on-site testing of equipment windings, with the exception of

motor-generator windings, or on oil-filled equipment.

kVA

1.5E

kVA

30E
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Table 19-3: Acceptable Power Factor Values

Item % P.F. at 20°C

Bushings, Condenser and Oil Filled 0.5

Bushings, Compound Filled 2.5

Transformers, Oil Filled, New 0.5

Transformers, Oil Filled 1.0 – 2.0

Cable, PILC 0.3

Cable, Varnish Canibric Insulated 4.0 – 8.0

Cable, Rubber Insulated 4.0 – 8.0

Exercise extreme care when applying the test voltage so as to avoid equipment damage. Successful

withstand of the voltage indicates satisfactory dielectric strength. In addition, a comparison of the

charging current between tests over a period of time will indicate the degree of deterioration of the

insulation as well as an examination of the plot of the leakage current vs. time during the “soak” portion

of the test.

Theoretically, the steady-state test current should be constant with time for any one value of applied

voltage. This constancy with time is a good indication that the insulation under test can withstand the

voltage being applied. Any tendency for this current to steadily increase with time at constant applied

voltage is a warning that the insulation under test may be damaged by a continuation of the test at that

voltage. A plot of total test current versus time should result in a curve as shown in Figure 19-1.

Figure 19-1: DC High Potential Test, Typical Test Current Versus Time

For an insulation test that is clean, dry, and free of voids, the test current at the lower voltage levels

should not only be constant with time, but should increase lineally at each higher voltage according to

Ohm’s Law. A plot of steady-state test current versus voltage will result in a graph as shown in Figure 19-2.
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Figure 19-2: Steady Current Versus Voltage

19.3.3.1 Equipment Required: DC high potential set, similar to those manufactured by Associated

Research, Inc., Biddle Company., Hipotronics Inc., Von Inc., and others (0 to l00 kV or higher, as

required).

19.3.3.2 Typical Test Voltages

Acceptance Tests: 80 to 85% of factory test voltage

Periodic Tests: 60 to 65% of factory test voltage (55 to 60% of factory test voltage with

PILC cable with neoprene jacket)

19.3.4 Dielectric Absorption Test

This test is again a test of the quality of the insulation. It is applicable to transformers, regulators, and

other similar devices as well as shielded high-voltage power cable. It is not possible to provide a range of

values for the results of this test. Its primary function is to provide an indication of deterioration prior to

complete failure.

This test is performed by charging the insulation under test with an insulation resistance test set. The test

is applied for a period sufficient to fully charge the cable. Resistance readings are taken every 15 seconds

during the first 3 minutes and at 1-minute intervals thereafter. The test shall continue until three equal

readings are obtained. This final reading shall be recorded. All windings or other conductors (in the case

of a cable) not being tested have to be grounded. The tank (or shields) has to be grounded also.

19.3.4.1 Equipment Required: 2500-volt motor-driven megger or multi-range megger with voltage

regulator.
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19.3.4.2 Typical Readings

Table 19-4: Typical Insulation Resistance Values

Condition

60:30 Sec.

Ratio

10:1 Min.

Ratio

Dangerous — Less than 1

Poor Less than 1.1 Less than 1.5

Questionable 1.1 to 1.25 1.5 to 2.0

Fair 1.25 to 1.4 2.0 to 3.0

Good 1.4 to 1.6 3.0 to 4.0

Excellent Above 1.6 Above 4.0

19.3.5 AC Over-Potential Test

This test is performed to verify the integrity of the insulation in low-voltage devices (600-volt and below)

and associated wiring. Observe specific manufacturers’ recommendations before applying this test to

solid-state components. The test consists of applying an ac voltage to the device for 1 minute and

verifying the successful withstand of this voltage.

19.3.5.1 Equipment Required: AC high potential set, similar to those manufactured by Biddle

Company or Hypotronics Inc. (0 to -2500V output or higher as required).

19.3.5.2 Test Voltages

Acceptance Tests: Twice the operating voltage plus 100 volts, but no less than 1500 volts

Periodic Tests: 1.7 times the operating voltage

19.3.6 Contact Resistance Test

This test is used to measure the resistance of the main contacts of a circuit breaker. A rise in resistance is

an indication of the need for maintenance or replacement of the contacts.

19.3.6.1 Equipment Required: A digital low-resistance ohmmeter as manufactured by the Biddle

Company, or similar.

19.3.6.2 Typical Readings: Refer to data provided by manufacturer with respect to the maximum

permissible resistance. Typical ranges, however, are as follows:

Circuit breakers: 10 to 50 micro-ohms (medium voltage)

50 to 350 micro-ohms (high voltage)

Reclosers: 50 to 200 micro-ohms

19.3.7 Winding Resistance Test

The winding resistance in a motor, transformer, regulator, etc., is not subject to change unless turns are

open or short-circuited. An accurate measurement of the resistance at time of acceptance will thus permit

future assessment of winding faults. Periodic checks will disclose shorted turns before further problems

occur. Results have to be corrected for temperature.
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19.3.7.1 Equipment Required: Kelvin Bridge suitable for measuring less than 1 ohm.

19.3.8 Insulating Oil Tests

Perform neutralization number, interfacial tension, dielectric strength, color, and visual examination tests

as described in IEEE Std. C57.106, “Guide for Acceptance and Maintenance of Insulating Oil in

Equipment.” A comparison of the values obtained for each test over a period of time will indicate the

gradual deterioration of the oil unless oil treatment has been performed. Sudden or accelerated changes in

the dielectric strength are not normally encountered. Should a large change occur, perform complete

inspection of the transformer rather than just instituting a treatment program.

A power factor test of the oil is a somewhat less accurate method of evaluating the dielectric strength of

the oil than the ASTM standard method. It is a suitable substitute if suitable facilities for the ASTM test

are not available.

It should be used, however, for periodic routine tests only. Tests conducted in association with trouble

finding should be by the ASTM method.

19.3.8.1 Equipment Required: Two options exist with respect to the performance of insulating oil

tests. The option adopted is generally a function of the size of the system, i.e., whether the need for such

tests is great enough to warrant the procurement of all equipment required. The two possibilities are:

1. Submit an oil sample to a qualified laboratory for determination of the neutralization number,

interfacial tension, dielectric strength, gas analysis, and color test.

2. Perform tests on site where possible, using the following equipment and methods:

a. Neutralization number. Calculate value by color-indicator titration method, ASTM

Std. D974.

b. Interfacial tension. Measure using a surface tension tester such as is manufactured by

Technical Associates or Fisher Scientific Co., ASTM Std. D971, ASTM Std. D2285.

c. Color test. Perform test in accordance with ASTM Std. D1500, which includes a field test

procedure. Submitting a sample to a testing laboratory is preferred.

d. Dielectric strength. Measure using a tester such as the megger or Hypotronics Oil tester,

ASTM Std. D877 or ASTM Std. D1816, as designated by the manufacturer.

19.3.8.2 Results: When the results of the insulating oil tests reach the following values, consider

performing the operation indicated:

• Neutralization number. When the number exceeds 0.35 to 0.5 for transformers or for circuit

breakers, reclaim the oil should. See IEEE Std. C57.106.

• Interfacial tension. When tension is less than 18-dynes/cm, reclaim the oil. See IEEE

Std. C57.106.

• Dielectric strength. When the dielectric strength is less than 28 kV with a standard gap,

recondition the oil by filtering.

• Color test. When color exceeds 3.5, reclaim the oil. See IEEE Std. C57.106.
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• Visual examination. If the oil is cloudy, dirty, or contains visible water, reclaim the oil. See

IEEE Std. C57.106.

For interpretation of test results gas in transformer oil, see IEEE Std. C57.104, “IEEE Guide for

Interpretation of Gases Generated in Oil-Immersed Transformers.”

19.3.9 Combustible Gas Analysis

A combustible gas analysis is performed to determine the amount, if any, of various types of combustible

gases in the transformer gas cushion. These combustible gases are produced over time by smallmagnitude turn-to-turn or other internal arcing faults. Internal arcing involving the core or other steel

parts may also result in particles of carbon in suspension. Upon detection of combustibles, repeat testing

at shorter intervals so as to ensure removal of the unit from service before major trouble occurs.

19.3.9.1 Equipment Required: It is generally desirable that a sample be submitted to a laboratory for

a complete analysis. This analysis will provide details of the specific gases present.

Results indicating 0.5 to 5.0 percent, by volume, of combustible gases indicate the probable existence of

an incipient fault. This necessitates close observance of the unit and the need for additional tests at

shorter intervals. With percentages higher than 5 percent, it is recommended that the unit be taken out of

service for detailed internal inspection. It is possible to examine the insulating oil itself for dissolved

gases and carbon in suspension. This should be accomplished in a laboratory. Similarly, the gas

collected in a “Buchholtz” relay should be analyzed in a laboratory.

19.3.10 SF6 Gas Analyses

SF6 gas used in circuit breakers is subject to contamination as a result of the products released during the

interruption of current. This contamination increases with the severity of the fault and with the

deterioration of the breaker contacts. Specific tests are not normally performed since the gas should be

reconditioned on a regular basis in accordance with the manufacturer’s recommendations.

Refer to specific equipment instruction books for additional requirements, if any.

19.3.11 Timing Test

A timing test is performed at the time of acceptance and again after all adjustments or replacements of

contacts in the circuit breakers. The test is used to verify that all poles of the circuit breaker and all series

contacts in each pole are operating simultaneously. Time the circuit breakers as close as possible to the

tolerances provided by the manufacturer.

19.3.11.1 Equipment Required: Depending on the type of circuit breaker being tested, use one of

the following test devices:

a. A circuit breaker operation analyzer such as one manufactured by the Cincinnati Clock and

Instrument Co. for breakers having a common operating shaft between poles such as is the

case with oil circuit breakers.

b. A multi-channel oscillograph for air blast and most SF6 circuit breakers. This oscillograph has

to have sufficient channels so as to provide one channel for every main contact and every
Bulletin 1724E-300

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resistor contact, and also for event marking such as time of energization of the operating

circuit. In all, probably a 24-channel unit is required. The unit should have a frequency

response of l50 to 5000 cycles per second.

19.3.12 Motion Analyzer Test

The motion analyzer test is conducted to verify the good condition and proper adjustment of the

mechanical operating linkages of a circuit breaker. A graphical representation of the elapsed time versus

distance traveled is plotted. Any wear or poor adjustment will result in a non-uniform curve. Conduct

this test in conjunction with the timing test.

19.3.12.1 Equipment Required: Circuit breaker operation analyzer as manufactured by the

Cincinnati Clock and Instrument Company, M & G Instrument Company, or Barnes Engineering

Company.

19.3.13 Series Overcurrent Test

Test all reclosers and low-voltage power circuit breakers having series trip devices periodically to verify

the calibration and proper operation of the device. Perform the test at a number of current levels so as to

verify the current versus time operating characteristics and the minimum instantaneous trip current level,

if applicable.

19.3.13.1 Equipment Required: Test equipment similar to that manufactured by Multi Amp

Corporation, General Electric Company, EIL Laboratories, etc., is required to provide a single-phase

calibrated current source.

19.3.14 Turns Ratio Test

Periodically perform a turns ratio test as an aid in detecting turn-to-turn short circuits in power and

instrument transformers. When evaluating the initial test results, give proper consideration to

manufacturing tolerances.

19.3.14.1 Equipment Required: A turn ratio test set as manufactured by the Biddle Company is a

convenient device. The test methods outlined in ANSI standards require less specialized equipment.

19.3.15 Polarity Test

Perform polarity tests on all power and instrument transformers after installation and again after any

removal and replacement of a unit.

19.3.15.1 Equipment Required: Same as indicated for the turns ratio test or a battery and a

d’Arsonval Meter.

19.3.16 Protective Relay System Tests

Subject all protective relays and each protective relaying scheme as a whole to operational tests at least

once per year. The test will vary depending on the particular scheme and component relays; however, the

test should in all cases be of the type where actual abnormal operating conditions are simulated and the

proper operation of all components is checked.
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Use multi-phase current and potential sources where applicable, rather than attempting to test multi-phase

devices with single-phase sources.

Whenever possible, use an oscillograph or other type of multi-input events recorder for timing of the

various components.

Refer to particular instruction books for specific test values, settings, and other pertinent data.

19.3.16.1 Equipment Required

a. Test set, as manufactured by AVO International or equal

b. Phase shifter, as manufactured by AVO International or equal

c. Auxiliary current and instrument transformers

d. Portable meters

19.3.17 Meter Calibration Tests

Test indicating instruments by comparison with a portable instrument that is connected into the same

circuit as the instrument being tested. Test switches are usually provided for this purpose on the front of

the panel.

Energy meter testing is usually performed in the cooperative’s meter shop and thus is not provided for at

the substation site.

19.3.17.1 Equipment Required: Many test methods are employed, each of which requires different

equipment. Typically, one of the following methods is used:

a. Portable standard loads

b. Portable rotating standard

c. Single-phase series tests

d. Element balance tests

e. When calibrating meters, the following loads should be used:

10% load at 1.0 pf.

100% load at 0.5 pf.

100% load at 1.0 pf.

19.3.18 Capacitance Test

Verify the capacitance coupling capacitors, the condenser section of bushings, and other similar

capacitive devices at time of installation. Periodic measurements are usually not made unless a specific

reason is incurred.

19.3.18.1 Equipment Required: Schering Bridge or equivalent.

19.3.19 Pressure Test

All high-pressure receivers and associated piping should be subjected to a pressure test at the time of

installation and any time thereafter when the system has been subjected to repairs, extensions, alterations,

etc. The pressure utilized for this test should be approximately 150 percent of normal pressure in systems
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that operate below 100 psi. In higher pressure systems, the normal operating pressure is usually

sufficient. In either case, seal the system and monitor the pressure over at least 8 hours (overnight is

preferable). The only pressure variations should be those caused by a change in temperature.

19.3.19.1 Equipment Required: The pressure gauge required is normally an integral part of the

system being tested.

19.3.20 Ground Grid Resistance Measurement

As noted in Chapter 18, Inspections, the ground grid resistance should be measured periodically to verify

that significant changes have not occurred as a result of changes in groundwater levels or other similar

natural phenomena. The value obtained should be compared with previously measured values or with

design criteria values in the case of a new installation.

19.3.20.1 Equipment Required: Three-probe measuring device similar to Vibroground equipment

as manufactured by Associated Research, Inc. or Biddle Company.

19.4 REFERENCES

ASTM Std. D877, “Test Method for Dielectric Breakdown Voltage of Insulating Liquids Using Disk

Electrodes.”

ASTM Std. D971, “Test Method for Interfacial Tension of Oil Against Water by the Ring Method.”

ASTM Std. D974, “Test Method for Acid and Base Number by Color-Indicator Titration.”

ASTM Std. D1500, “Test Method for ASTM Color of Petroleum Products (ASTM Color Scale).”

ASTM Std. D1816, “Test Method for Dielectric Breakdown Voltage of Insulating Oils of Petroleum

Origin Using VDE Electrodes.”

ASTM Std. D2285, “Test Method for Interfacial Tension of Electrical Insulating Oils of Petroleum Origin

Against Water by the Drop-Weight Method.”

IEEE Std. C57.104, “Guide for Interpretation of Gases Generated in Oil-Immersed Transformers.”

IEEE Std. C57.106, “Guide for Acceptance and Maintenance of Insulating Oil in Equipment.”
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CHAPTER 20

MAINTENANCE

An effective and efficient maintenance program for substation equipment includes scheduled periodic

maintenance as well as corrective procedures that address specific equipment-related problems.

20.1 GENERAL

Periodic or time interval-based maintenance procedures, more commonly referred to as preventive

maintenance, are developed and instituted in an attempt to minimize unscheduled service interruptions.

The degree of success of such procedures is generally reflected by the cooperative’s ability to balance

system reliability with accepted levels of risk of failure or system outage.

Periodic maintenance procedures are generally performed in conjunction with normally scheduled

inspection and testing programs, which are outlined in Chapters 18, Inspection, and 19, Tests.

Specific details for the performance of periodic maintenance vary considerably depending on the make,

model, age, load profile, etc. of the specific equipment. In addition, a maintenance program developed

for substation equipment should consider site environmental conditions, site location and access, and

priority of the substation equipment to overall system reliability.

Refer to manufacturers’ instruction books for all equipment requirements.

20.1.1 Records

Maintain a record of inspection and test results that indicate the condition of equipment and the

maintenance history, as outlined in Chapter 18, Inspection, in an electronic database. In addition to the

details contained therein, include at least the following information in these records:

1. A description or outline of the basis for the specific maintenance program

2. The date when maintenance was performed and the latest date when it should again be

performed

3. The condition of the equipment after the inspection or maintenance

4. Any requirements for special follow-up work

20.1.2 Safety

Certain maintenance procedures may be performed with the equipment in service while other procedures

require that the equipment be de-energized. Scheduled outages closely coordinated with power plant or

transmission line maintenance quite frequently afford the best opportunity for maintenance. When it is

necessary to remove a piece of equipment from service without de-energizing the total substation,

maintain minimum safety clearances as specified in Chapter 18. Install temporary barriers to isolate the

equipment being worked on from adjacent energized equipment.

20.2 PERIODIC MAINTENANCE

Periodic maintenance programs should consider original equipment manufacturers’ (OEM)

recommendations with respect to details of the maintenance performed and to its frequency. OEM
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recommendations for maintenance are typically conservative. Cooperatives should look for ways to

perform equipment maintenance based on actual conditions. A study of all industries shows that overly

conservative maintenance based on OEM recommendations can lead to more failures of equipment that

might otherwise be functional. Common maintenance procedures and their frequencies are indicated in

Table 20-l.

Table 20-1: Recommendations for Periodic Maintenance

Maintenance

Procedure

Equipment

Clean Exposed

Porcelain

Clean, Lubricate &

Adjust Mech.

Clean or Replace and

Align Contacts

Tighten Connections

Major Overhaul

Clean & Burnish

Contacts

Lubricate Aux. Motors

Replace Dehydrator in

Breather

Change Oil in

Gear Boxes

Check Liquid Levels

Transformers, Inert Gas Cushioned 12 12 6

Regulators 12 12

Oil Circuit Breakers 12 12 12 *

Air Circuit Breakers 12 12 12 *

Vacuum Circuit Breakers 12 12 12 *

SF6 Circuit Breakers 12 12 12 *

Air Blast Circuit Breakers 12 12 12 *

PTs 12 12

CTs 12 12

CCPDs 12 12

Surge Arresters 12 12

Disconnects and Air Break Switches 12 12 12 12 6 24

Vacuum Switches 12 12 12

Circuit Switches 12 12 12

Capacitors 12 12

Metal-Clad Switchgear 12 12

Relays 12 12

Transformer Tap Changer Mech. *

Transformer, Conservator Type 12 12 6

Station Battery 2

Number indicates recommended interval of time (in calendar months) between maintenance times.

Asterisk (*) indicates that the requirement for maintenance is a function of the number and/or type of

operations.

20.2.1 Specific Requirements

In addition to those items of maintenance listed in Table 20-l, the following maintenance tasks should be

performed at the time regular visual inspections are made:

1. Eliminate any low spots that have developed in the substation yard.

2. Remove trash from the area.

3. Replace all burned-out lamps.

4. Remove bird nests and other items from the vicinity of energized parts.

5. Clean and refinish defects in paint and galvanizing.

6. Periodically remove vegetation. If chemical application for removal of vegetation is required,

consult the local farm extension agency or governing authority for proper methods and

chemicals.
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Exercise extreme caution if maintenance is performed near energized equipment.

20.2.2 Painting

Periodically, depending on the geographic location, local environment, etc., equipment, fences, and

structures have to be repainted. The following should be considered as minimum requirements:

20.2.2.1 Equipment and Other Painted Items

a. Thoroughly remove all loose paint, blisters, and scale. Where the condition of the finish is

poor remove the paint entirely. Wire brushing, sand papering, or scraping is desirable where

only partial surface cleaning is necessary. Paint removers will soften and aid in removal.

However, neutralize the paint remover before attempting to paint. For removal of oil and dirt,

use weak solvents such as mineral spirits, other petroleum thinners, or turpentine substitutes.

b. Paint as soon as possible after cleaning. Cover all bare metal with a primer. Where only

chalking has occurred, one finish coat is sufficient. Primer and finish paints may be obtained

from most equipment manufacturers and sometimes from local sources. A zinc chromate

alkyd resin primer followed by an alkyd base paint is a suitable air-dry combination for

exterior surfaces. Allow the primer coat to air-dry thoroughly and follow it with two finish

coats with sufficient time allowed between coats for drying.

20.2.2.2 Galvanized Structures and Fences

The protective coating produced by the galvanizing process is normally a long-lived coating; however,

the coating will eventually fail and rust will appear. It has been observed that Class II hot-dipped

galvanizing on chain link fences in rural locations will normally furnish adequate protection for many

years. The life of the coating on structural steel used in substations should generally be longer than

12 years, except possibly for upper flat surfaces of horizontal members. Any failure of the coating will

usually occur in spots rather than over an entire surface. The following procedure is recommended:

a. Clean the surface with a wire brush or by other mechanical means to remove rust and dirt. If

the surface is contaminated with grease or oil, use a solvent to remove those contaminants.

Mineral spirits or a weak solution of trisodium phosphate can be used as the solvent. A

solution of 1 ounce of trisodium phosphate to 1 gallon of warm water is suggested for cleaning

the metal. In the event that it is uneconomical or impractical to remove all rust, a reasonably

satisfactory job can be obtained by deactivating the rust through chemical treatment. A weak

solution of phosphoric acid is suggested for deactivating rust. Use proper skin and eye

protection.

b. Apply a priming coat to the clear dry surface using a good zinc dust–zinc oxide paint. Allow

ample time for the paint to dry before applying the finish coats.

c. Apply two finish coats using the same type of paint as was used for priming. Allow ample

drying time between finish coats. One finish coat is needed for areas on which the galvanized

coating remains intact. The color of the paint is gray, but colors in oil may be added to the

finish coats to obtain other shades. Other paints normally used as final coats for metal (such

as aluminum paint) may be used as the final coat in place of the zinc dust–zinc oxide paint.
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It is recommended that painting of outdoor metal work be done only when the temperature is above 7.2°C

(45°F) and when the relative humidity is below 80 percent.

The durability of paint coating depends on thickness, cohesion, and continuity. Generally 5 mils

(0.005 inch) is an adequate thickness. The thickness should be uniform, and paint should not be easily

scraped off the metal. Pay particular attention to welds, edges, and other hard-to-coat areas.

20.3 UNSCHEDULED MAINTENANCE

Any abnormal conditions that are noted during any inspection of the substation yard or equipment may

need to be corrected as soon as possible, depending on the severity of the condition. In some cases, the

equipment has to be removed from service prior to beginning maintenance. Some abnormal conditions

and possible corrective measures may include the following:

1. Loose or Corroded Connections. Tighten or replace, depending on condition.

2. Contaminated Bushings. Clean all exposed surfaces, including casing, porcelain, and oil

gauges.

3. Leaking or Damaged Bushings. Repair or replace.

4. Deteriorated Insulating Oil. Recondition or reclaim depending on situation (see IEEE

Std. C57.106 and Chapter 19 of this bulletin).

5. Low Pressure of Inert Gas Cushion. Replace gas cylinder if required and check gas system

for leaks, etc.

6. Pressure Relief Device Operated. Reset device and determine cause for operation.

7. Oil Leaks. Repair, tighten, weld, etc., as required.

8. Sludge or Carbon Deposits in Tank. Remove deposits and clean. Determine cause for

deposit, i.e., deteriorated oil, internal faults, etc.

9. Damaged Items. In addition to the items contained in the previous paragraphs, it can be

anticipated that certain abnormal items will be noted that can only be remedied by replacement

of the damaged item. These include:

a. Damaged potheads, high-voltage cable, porcelain (bushings, surge arresters, insulators,

etc.), and other items subject to high electric stress.

b. Failing capacitors, as evidenced by insulating fluid leaks around bushings or bases, bulging

tanks, blown fuses on individual units or groups of units, etc.

NOTE: It may be necessary to de-magnetize the core in current transformers if they have been subjected

to very high magnitude currents that have resulted in saturating the core. Modern high-accuracy current

transformers show relatively little change in accuracy as a result of magnetization. However, should a

current transformer core become magnetized by surges as a result of opening the primary circuit under

heavy load or any other means, it may be conveniently demagnetized by several methods.

One reliable method requires connection of a variable ac source to the secondary of the current

transformer to be demagnitized after the power circuit has been de-energized. During the test, the

primary of the current transformer is left open-circuited. The secondary winding current is slowly

increased from 0 to 5 amperes, and then steadily reduced to 0 again before disconnecting the test source

from the secondary winding.

It is important to note that, when demagnetizing high-impedance current transformers, it may require up

to 450 volts or higher across the secondary terminals. Appropriate caution is required.
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20.4 RELIABILITY-CENTERED MAINTENANCE

As equipment in substations deteriorates and degrades over time, the probability of service interruptions

as a result of component failure is increasing at the very time that competitive pressures demand higher

levels of power quality and reliability. Some utilities are working to proactively address these issues by

implementing a condition-based, predictive substation maintenance program using the concepts of

reliability-centered maintenance.

Reliability is defined as the probability that a system will perform a given function satisfactorily for a

specified time under specified operating conditions.

The fundamental goals of reliability-centered maintenance are to preserve the function or operation of a

system and to schedule all preventive maintenance tasks. The system function that has to be preserved in

substations is the delivery of safe, reliable electric power to customers.

There are four fundamental principles of pure reliability-centered maintenance theory:

1. The primary objective of reliability-centered maintenance is to preserve system function.

2. A good reliability-centered maintenance program should identify specific failure modes to

define loss of function or functional failure.

3. A reliability-centered maintenance program should prioritize the importance of the failure

modes.

4. A reliability-centered maintenance program should identify effective and applicable

preventive maintenance tasks.

20.4.1 Methods

A reliability-centered maintenance program may be used to identify the appropriate application of the

four traditional methods of asset maintenance performed today. The four methods of equipment

maintenance are corrective, preventive, proactive, and predictive.

Corrective maintenance is a reactive form of maintenance that uses a system failure as a signal to perform

a repair task. For non-critical components or components that do not permit cost-effective maintenance,

corrective maintenance is acceptable. However, a run-to-failure approach is not acceptable if the system

function is lost or the cost of the maintenance task that would have prevented failure is reasonable relative

to the cost of the outage.

Preventive maintenance is a time interval- or usage rate-based maintenance method. Anthony Smith,

author of Reliability Centered Maintenance, has identified ten common maintenance problems

encountered in traditional preventive maintenance programs for industry in general that support the need

for a better method of performing preventive maintenance:

1. Insufficient proactive maintenance because most effort is in corrective maintenance (i.e.,

responding or reacting to problems)

2. Frequent problem repetition because there is only time to restore a system to operation and no

time or effort spent to determine the cause and repair the root of the problem

3. Erroneous maintenance work that leads to a plant outage

4. Proven maintenance practices that are not communicated, taught, or implemented

5. Unnecessary and conservative preventive maintenance that does not contribute to overall plant

reliability and contributes to human error
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6. Unclear rationale for preventive maintenance with undocumented procedures that have no

logical background or theoretical basis

7. Maintenance programs that lack good record keeping or a method to track the decision making

process

8. Use and acceptance of OEM recommendations for maintenance practices that do not apply to

specific site conditions and that may be conservative so as to protect the OEM’s warranties

9. Lack of standard practices among similar facilities

10. Lack of quality, practical, predictive maintenance tools and procedures

Two key questions have to be answered in a traditional preventive maintenance program: (1) What tasks

have to be performed? (2) When should they be performed?

Reliability-centered maintenance not only asks what preventive maintenance task should be performed

and when it should be performed, but it answers “why” a preventive maintenance task is needed.

Reliability-centered maintenance uses a process known as age exploration to determine preventive

maintenance intervals for components in which there is no determinable age–reliability relationship. If

the regular preventive maintenance interval reveals no signs of degradation or incipient failure, the

interval to the next preventive maintenance overhaul or inspection is increased by 10 percent. If again

there are no signs of degradation or incipient failure, the process is repeated, adding 10 percent to the

interval each time until the component requires attention or replacement. The maintenance interval is

then reduced by 10 percent and that interval becomes the final task interval.

Reliability-centered maintenance clearly defines and documents reasons for how and why each preventive

maintenance task is selected.

Proactive maintenance is the upgrade or redesign of components that consistently fail under normal

design loading criteria or that violate safety codes, regulations, or guidelines. Proactive maintenance

tasks typically result from the need to perform corrective maintenance because of system functional

failure.

Predictive maintenance is based on the operating condition of a component. No component should have

preventive maintenance performed on it unless its actual condition warrants the task. Predictive

maintenance gives a snapshot in time of the actual operating condition of a component without

interrupting the function of the component. A predictive maintenance approach allows the preventive

maintenance task to be scheduled and reduces overall operations and maintenance costs by dramatically

reducing corrective maintenance tasks.

Of the four traditional methods of maintenance, the predictive maintenance approach seems to be the

most sensible. The ability to predict system failure and act precludes corrective maintenance. Knowing

the actual operating condition of equipment provides the user the reason why any preventive maintenance

should be performed. Proactive maintenance can be considered as more of a function of engineering

analysis due to a consistent failure of a part or component. As a result, there is a growing number of

predictive maintenance approaches for substation equipment on the market today.

20.4.2 Application

The best approaches adapt reliability-centered maintenance theory in a practical, understandable manner

to 1) prioritize assets, 2) assess the condition of the equipment based on known failure modes, and 3)

identify and schedule effective preventive maintenance.
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The application of reliability-centered maintenance to substations requires a careful and detailed

prioritization of where the next maintenance dollars will be spent in order to improve system reliability of

those prioritized assets that have the greatest impact on system function. The diverse attributes that

contribute to this process include:

• Substation voltage

• Equipment age

• The number of sensitive customers directly or indirectly served by the circuits out of the

substation

• The total number of breaker operations to date

• The total number of extended outages to date

Maintenance logs and system operations logs will provide this operational information. Each parameter

is weighed according to relative importance as determined by engineering judgment, with a heavy

emphasis placed on customers served and outage history. The parameters and weightings can be entered

into a spreadsheet to calculate system priorities. Each parameter will be multiplied by its assigned

weighting, and all the parameters for each substation will be summed to provide an overall score.

A sensitivity analysis can be made to vary the weightings as needed. The spreadsheet can then sort the

substations in ascending order, providing the user with the first substations that deserve a detailed

predictive assessment.

Assessing the condition of the parts and components of a high-priority substation starts with a detailed

assessment of existing maintenance activities. Interview key personnel from top to bottom of the

maintenance organization to discover what maintenance practices are perceived to occur and what

practices actually occur. This discovery process helps to define the culture of a maintenance organization

and identifies the current approach to substation maintenance. In addition, conduct a thorough review of

maintenance records to identify and document specific problem equipment and recent corrective

maintenance activity at the selected substation. The assessment may reveal the lack of information or the

need to better manage the information.

The next step in the assessment of the parts and components of a high-priority substation is the

performance of a Detailed Inspection Procedure and Online Equipment Evaluation.

The Detailed Inspection Procedure guides an experienced field inspector through the step-by-step

inspection of major substation equipment by identifying specific failure modes for equipment that can be

verified by visual observation or examination of the maintenance records. Inspect each major electrical

and structural component of a substation: transformers, breakers, arrestors, circuit switches, disconnect

switches, capacitor banks, batteries, relays, switchgear, insulators, terminations, buswork, current and

potential devices, grounding, support structures, concrete foundations and control trench, control building,

and site civil conditions.

The Detailed Inspection Procedure prompts the inspector to provide a percentage condition adjustment

factor based on a recommended condition range for each major substation component. The percentage

condition adjustment rewards or penalizes components based on visible failure modes that can impact the

function of the component or the entire substation. The percentage condition adjustment is an attempt to

prioritize preventive maintenance tasks and provide guidance for subsequent inspections on the visible,

external aspects of a substation and is not an attempt to quantify the projected functional life of a

component. For additional information on inspection, see Chapter 18, Inspection.
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Once the Detailed Inspection Procedure and Online Equipment Evaluation are complete, it is important to

report on prioritized action items for scheduled preventive maintenance. The substation components with

the greatest negative percentage condition adjustment (e.g., component function is heavily impacted by

visible incipient failure modes) receive the highest priority for scheduled preventive maintenance.

In addition, occurrence reports based on the results of the Online Equipment Evaluation prioritize the

need for scheduled preventive maintenance on the internal components of substation equipment. High

inaudible noise levels, unusual temperature differentials, slow breaker operations, or contaminated oil

samples provide good reasons why preventive maintenance should be scheduled. Lack of any unusual

characteristics in the Online Equipment Evaluation may indicate that there is no reason to perform routine

preventive maintenance because of the actual operating condition of the equipment.

Repeat this Detailed Inspection Procedure and the Online Equipment Evaluation process for the second

highest priority substation. Set regular inspection intervals using age exploration.

As the concepts of reliability-centered maintenance are implemented for each substation on the system,

the user can expect to know why preventive maintenance tasks are performed and can expect to achieve

the following results:

1. Better system availability and reliability

2. Increased worker safety

3. Extended equipment life

4. Improved long-range planning for asset management

5. More cost-effective preventive maintenance as a result of scheduling men and equipment

6. Reduced O&M expenses due to reduced corrective maintenance costs

The results of a Detailed Inspection Procedure and Online Equipment Evaluation identify the highest

priority “accidents waiting to happen” so that corrective measures can be immediately scheduled to

maintain system function. As a result, the cost of corrective maintenance in the form of scheduled

preventive maintenance may initially increase substation maintenance budgets. However, over time, the

application of reliability-centered maintenance improves system reliability and reduces O&M expenses.

20.4.3 Conclusion

The fundamental goal of reliability-centered maintenance is to preserve the function or operation of a

system. Specifically, the function that has to be preserved for electric substations is the delivery of safe,

reliable electric power to customers. The concepts of reliability-centered maintenance that have been

used so effectively in other industries can be applied to electric substations in a viable and effective

maintenance approach that proactively addresses the challenges of improving system reliability and

controlling costs in an increasingly competitive energy delivery market.

20.5 REFERENCES

IEEE Std. C57.106, “Guide for Acceptance and Maintenance of Insulating Oil in Equipment.”

IEEE Std. P1266, “Trial-Use Guide for Evaluation and Development of Substation Life Extension

Programs.”

Smith, Anthony M., Reliability Centered Maintenance, New York: McGraw-Hill, 1993. ISBN 0-07-

059046-X.
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CHAPTER 21

UPRATING AND EXPANDING EXISTING SUBSTATIONS

21.1 APPLICABILITY

All substation design and construction including uprating and expanding has to be based on sound

practices to ensure safe, reliable operation. While it may not always be practical in uprating to attain

every desired recommended clearance and spacing, minimums where established in this bulletin or other

applicable national or local standards have to be met or exceeded.

Modern practice requires that certain environmental and safety issues be addressed in any substation

uprating or expansion project, even though the existing substation may not have been designed with such

issues in mind. Seismic criteria for the area of installation have to be considered. A suitable oil spill

prevention plan, possibly including oil containment facilities, has to be implemented. Fire protection

methods (including physical separation, barrier walls, and sprinkler systems) should be weighed against

the safety concerns and the costs of fire insurance to arrive at an appropriate design. Several other

environmental issues should be considered, as applicable: noise abatement, aesthetics, disposal and

containment of hazardous materials, and containment of electromagnetic fields.

21.2 FEASIBILITY

Cost is usually a primary factor when determining a course of action: construction of a new facility

versus uprating and/or expanding an existing facility. Prepare construction cost estimates for the schemes

under consideration. Generally choose the plan with the most favorable cost/benefit ratio, provided that

such action is consistent with the near- and long-range system plan.

With facility expansion or new construction, include in cost estimates potential impacts due to

underground obstructions and environmental concerns.

Consider substation uprating as an alternative where increased capacity is required and routine expansion

is hindered due to lack of land area. During the initial planning of an uprating program, it may become

apparent, after discussions with manufacturers, that such a program is not cost-effective. In this case,

expansion or new construction is usually the most desirable course of action.

21.3 SUBSTATION UPRATING

In uprating substation equipment, the cooperation of the equipment manufacturer is usually required.

Although an agent or distributor for the equipment vendor may initially be contacted, obtain final

determinations from the manufacturer’s headquarters engineering staff as to technical feasibility of the

uprating, the cost of such work, and where the work can be done—field or manufacturing plant. It may

be necessary for the work to be performed at the manufacturer’s facilities or by its field service personnel

to obtain proper warranty of the uprated equipment.

When equipment uprating is being considered, only the capacity is increased. The voltage level remains

the same. Normally the location of incoming or outgoing circuits remains the same although they may be

reconductored for increased capacity.
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21.3.1 Major Equipment Uprating

21.3.1.1 Power Transformer: In the initial phase of a planned substation uprating, furnish the power

transformer manufacturer with complete nameplate data. Additionally, supply original purchase

information, such as purchase order number and date. This information will make it possible for the

manufacturer to retrieve the original design calculations to determine the possible additional capacity.

If the original design was conservative, some additional capacity may be possible. A loading history may

be necessary to confirm this. If the unit is oil insulated, self-cooled, the addition of radiators and fans

should provide added capacity. If the unit is fan-cooled, additional or larger fans or radiators may add to

available capacity. Insulating oil pumping, or additional pumping, may be necessary to further increase

the rating. In some cases, internal leads may require inspection, testing, and even replacement.

There are variations between manufacturers but, in general, a 15 to 20 percent increase in MVA capacity

may be possible.

21.3.1.2 Oil Circuit Breaker: Increasing the MVA capacity of a substation may necessitate

increased circuit breaker ratings. Breakers may be inadequately rated for increased continuous and

momentary currents and interrupting duty. Consequently, determine the fault and continuous current

requirements of all associated breakers.

The existing oil circuit breakers may be adequate for the increased full load current but inadequate for the

interrupting duty to be imposed.

Give the manufacturer of the breakers complete nameplate and purchase data together with the ultimate

full load current and asymmetrical fault current expected from the uprating program.

From this data the feasibility of the program can be determined as far as the breakers are concerned.

New contacts and bushings may possibly overcome any full load current deficiency. Replacement of

interrupter units could safely handle the increased interrupting duty.

Application of capacitors on a substation bus causes severe capacitive current switching duty. Compare

rated capacitive switching current for the existing breakers with the anticipated duty to determine the need

for breaker mechanism modifications. Consult the breaker manufacturer to determine the need for such

modifications.

21.3.1.3 Current Transformer (CT): Current transformers should be evaluated for thermal rating

under the uprate program by the equipment manufacturer when the apparatus is being assessed. If

determined inadequate, replacement will be necessary. Next determine the ratio suitability. For example,

a 3000/5 multi-ratio CT, being operated on the 1200/5 tap, can be reconnected for 2000/5 service.

Application of multi-ratio CTs on lower rated taps results in less accuracy and can lead to saturation of

the CTs (with associated error) under heavy fault conditions. Consider these features in the CT

evaluation when fault currents are increased.

21.3.1.4 Wave Trap: Since a wave trap or line trap is a current-rated device, it is undesirable to

operate such equipment above the nameplate rating. In most cases of uprating, wave traps will require

replacement.
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21.3.1.5 Coupling Capacitor Voltage Transformer (CCVT): A CCVT is a voltage-rated device as

is the associated line coupling tuner when the CCVT is equipped with carrier current accessories.

Replacement will not be required for a capacity uprating program unless the addition of new metering or

relaying exceeds the loading limits of the device.

21.3.1.6 Voltage Transformer (VT): A VT is in the same category as a CCVT relative to uprating.

21.3.1.7 Bus System: Two factors enter the uprating considerations regarding the substation bus

system:

1. Current-carrying capacity of the conductors and connections

2. Fault current capability of the conductor support systems

An increase in bus current is directly proportional to the increase in substation MW capacity. However,

the increase in bus heating is proportional to the current squared (I2R). This heat increase has to be

considered. Additional heat may, by conduction, affect connected apparatus. Also, it becomes

progressively more difficult to maintain good bolted joints, free from deterioration, as the temperature

increases. For these reasons, good practice generally indicates rating the bus for a 30°C (54°F) rise over a

40°C (104°F) ambient under full load conditions. Under emergency conditions consider a 25 percent

maximum bus current increase. These loadings should, however, be limited to a couple of days’ duration.

For heat rise computations, the necessary data and mathematical relations are available from conductor

manufacturers and industry associations. An excellent publication of this nature, Aluminum Electrical

Conductor Handbook , is available from The Aluminum Association, 750 Third Avenue, New York, NY

10017.

Once the thermal considerations of the uprated bus have been calculated, decide if the existing conductor

should remain or be replaced. If strain bus, possibly only the drops need changing to a larger size. If the

substation uprating is a measure to buy time prior to a more extensive program to serve load growth,

possibly the bus need not be replaced.

The fault currents associated with a substation, in the case of rigid bus mounted with apparatus insulators

on structures, cause stress in the insulators and structures. With the added capacity and consequent

increase of the fault current, calculate these stresses be to determine if insulators or structures are

adequate. Methods of calculation are described in Chapters 4 and 7.

The insulator cantilever strength will most likely be the weak element under the uprated condition.

Several courses are open to remedy this situation. Insulators of increased cantilever strength can be

installed on the center phase only. However, it may be necessary to change all insulators to higher

strength, depending on the calculated forces. Additional bus structures to reduce bus span length may be

an answer, although probably a costly solution. An alternative solution may be the addition of interphase,

fiberglass insulators. Coordination with manufacturers is necessary to find a device that will work

properly. Calculations are needed to verify that the additional weight that would be added to the bus is

acceptable to the existing design.

21.3.1.8 Disconnecting Switches: The increased current of the uprated substation will require that

the disconnecting switches be examined for full load rating. This can be done from the substation records

or the switch nameplates. Also check the momentary current capability. If either the full load or

momentary currents are found inadequate, consult the original equipment manufacturer. It may be
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possible to uprate the switches by additions or replacement of the current-carrying parts and insulators. If

this is not possible or the switch vendor no longer manufactures this product, replace the units.

21.3.1.9 Surge Arresters: Since the voltage level or substation BIL is not usually increased in the

uprating program, the surge (lightning) arresters need not be changed. However, if the existing units are

of old and outdated design, it is advisable to replace, in particular, those positioned for power transformer

protection. Generally, silicon carbide arresters should be replaced with metal oxide arresters for the

improved protection characteristics that are available.

21.3.1.10 Raceway System: Essentially, the only changes in the raceway system would be

provisions for additional transformer fan and oil pump circuits. If the system is underground and spare

raceways or ducts have not been provided, new direct burial plastic conduits can be installed above or

beside existing duct banks, thus using the present routing.

21.3.1.11 Auxiliary Systems: In an uprating program the essential addition to the auxiliary systems

will probably include new ac circuits for transformer fans and oil pumps. Consider these circuits as

critical or essential loads and assign them a 100 percent demand factor. It is doubtful that the auxiliary

system transformers, panelboards, and service conductors will need increasing in size. Normally these

are specified conservatively. In addition, the operating history of the substation may indicate that the

existing loads were assigned a demand factor in excess of the true factor. However, check the auxiliary

system capacity nevertheless for adequacy. An additional panelboard may be required to provide for

additional circuits. Consider fault current ratings of equipment downstream of an uprated auxiliary

system transformer.

The most important equipment check to make of the ac system in an uprating program is the capacity of

the automatic transfer switch. This switch may have to be replaced with a unit having a larger rating,

both full load and momentary.

It is unlikely that the battery and charger system will be affected by a substation uprating, but also check

these components to verify their adequacy.

21.3.1.12 Relaying and Metering: Unless the relaying scheme is being changed concurrently with

the substation uprating program, the changes to existing relays will usually consist of revising the

settings. Higher fault current ratings may result in the need for complete re-coordination of feeder and

bus relaying. Some current transformers may have to be reconnected or replaced for different ratios both

for relaying and metering. Since there is usually no voltage change in an uprating program, potential

transformers and other voltage devices generally can remain the same.

21.4 SUBSTATION EXPANSION

21.4.1 General

Substation expansion is the addition of transmission, subtransmission, or distribution circuits to existing

substations. These additional circuits may be required on the primary or secondary side. In some cases

modifications to the switching scheme may be necessary or desirable. At the same time, capacity may be

increased with the installation of an additional transformer(s). Figure 21-1 shows a substation expansion

adding 69 kV line, a 69/12 kV transformer, and a 12 kV distribution structure to an existing substation

consisting of 69 kV line, a 69/34.5 kV transformer, and a 34.5 kV distribution structure.
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Figure 21-1: Substation Expansion

A planned expansion is also the time to consider the possibility of a different voltage level, for example,

whether the expansion of a 115 kV substation be designed for future 230 kV. Phase-to-phase rigid bus

spacing is nominally 2.13 meters (7 feet) and 3.35 meters (11 feet), respectively. Installing structures and

buswork for a higher voltage spacing and clearance with operation at the present voltage may be

warranted when the long-range system plan indicates increasing the voltage at a later date. When the

expansion goes to the higher voltage, this portion could be coupled to the existing voltage through a

suitable transformer or completely divorced from the lower voltage installation, depending on system

configuration.
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If a higher voltage construction is decided for the expansion and the higher voltage is contemplated within

the near term (less than 10 years), design and install foundations for the higher voltage equipment. The

advantages of the monolithic pour over the modification of a smaller foundation at a later date far

outweigh the higher cost.

Reasonable equipment dimensions and weights for the higher voltage equipment are readily available

from equipment manufacturers. The trend is to smaller, not larger, equipment so this risk is reasonable.

If future bus extensions are anticipated, it may be advantageous to install disconnect switches on the ends

of the bus to facilitate the future construction with minimal outages. With the switches open, future bus

extensions can be made on the dead side of the switch without de-energizing the existing bus.

When land availability is a concern, gas-insulated substations (GIS) are a compact, though costly,

solution to restricted space requirements. Typically, such installations become more economical in the

230 kV and higher voltages, but contact equipment vendors to determine applicability for a given

installation.

21.4.2 Site Work

If the expansion land area was originally set aside for a lower voltage, it has to be enlarged to

accommodate the future higher voltage.

Obtain additional soil data in the expansion area. It would be an invalid assumption to take for granted

that conditions in the existing site carried on to the expansion area.

Other criteria for site work are covered in Chapter 6, Site Design.

21.4.3 Grounding

Take ground resistivity measurements in the expansion area. These can often be obtained along with the

soil data.

A reasonable estimate of ground fault current can be calculated for the proposed higher voltage. Design

the grounding system for this higher voltage using the methods described in Chapter 9, Grounding.

21.4.4 Raceway System

If the existing substation employs an underground duct system, this does not in itself mandate the

expansion to this method.

As described in Chapter 10, cable trench has certain advantages over ducts. A large handhole can be

designed to interface the existing ducts to a trench and the advantages of trench used throughout the

expansion area. If the expansion area is later separated from the existing area, the handhole becomes an

ideal point of electrical separation.

When the higher voltage level is built, the trench can be paralleled with the other trench for the increased

cable requirements with segregation usually occurring at this level.
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In substations 230 kV and above, there may be concern with shielding of control cables. Make an effort

to provide appropriate shielding and segregation of cables routed in cable trench beneath the high-voltage

buses.

21.4.5 Control House

Unless substation expansion was planned in the original design and the control house sized accordingly, it

will probably require enlarging. Design the enlargement with the higher, future voltage in mind.

Expansion of the existing control house may or may not be feasible because of physical obstructions or

limitations in the construction methods originally used. It may be necessary to build a separate control

house, interconnected with the original house by the necessary cable and raceway. Expansion of the

existing control house is the preferred method, since it allows for all controls within the same building.

Layout of the house should take into consideration the optimum arrangement of control panels to

facilitate operations.

21.4.6 Equipment

21.4.6.1 Bus System: Make a conservative estimate of expected fault currents at the higher voltage

level and establish the bus BIL along with ground clearances to personnel, roads, and fencing. Following

the methods outlined in other chapters, design the bus and insulators at this level taking into account

contemplated full load bus current.

21.4.6.2 Transformers and Circuit Breakers: The selection of transformers and circuit breakers

together with their associated isolating switches is detailed in other chapters of this guide. Specify this

equipment for the operating voltage. Design foundations and switch structures for the higher, future

voltage. When the higher voltage becomes a reality, cutover will be more orderly and less timeconsuming. Specify disconnecting switches with the phase spacing of the higher level.

21.4.6.3 Carrier Equipment, Surge Arresters, and Voltage Devices: Specify this equipment at the

operating voltage. However, foundations and supporting structures can and should be designed for the

higher voltage for the reasons set forth previously.

21.4.6.4 Auxiliary Systems: Check and possibly revise or increase in capacity several equipment

items in the auxiliary systems to successfully expand an existing substation:

1. Auxiliary transformer capacity

2. Throwover switch ratings, full load and momentary

3. Low-voltage ac and dc panel circuit capacity and adequacy of mains

4. Low-voltage switchgear circuit capacity

5. Battery and charger capacity

Redesign or modification of the auxiliary system of the expanded substation is accomplished by summing

existing loads with the expansion loads and proceeding as outlined in Chapter 15, AC and DC Auxiliary

Systems, for a new installation.

A review of the operating history of the ac system may reveal that the originally assigned demand factors

were overly conservative, and the existing capacity may be adequate for the substation expansion.
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The same could be true regarding the throwover switch. In the interest of reliability, any deficiency,

however slight, indicates replacement of this switch.

Well-designed ac and dc systems should have provided ample spare panel circuits and adequate mains.

This may not have been done because no expansion was ever considered possible at the particular

installation under consideration. A new panel can be tied directly to the existing panel by doubling the

main lugs of the existing unit. Locate the new panel close to the existing and full-ampere capacity cable

installed.

Low-voltage switchgear falls into the same category as the panels. Additions can be made in the same

way using individual fused switches or circuit breakers.

The dc battery and charger, if not originally specified for equipment additions and/or if found inadequate,

should be replaced for the substation expansion.

21.4.6.5 Relaying, Metering and Control: If the same relaying scheme as existing is applied to the

substation expansion, the only requirement is the addition of relay panels for the expansion together with

associated control panels. In this situation, the metering scheme would undoubtedly remain the same

with equipment duplicating the existing equipment.

The different loading conditions of the substation with the expansion may require resetting of the relays

of the existing portion. Re-coordination of feeder and bus relaying, as well as evaluation of CT ratios,

may be required.

The reason for the expansion program may dictate more complex, sophisticated protective relaying, both

for the existing and the expanded substation. A situation such as this is practically identical to a

completely new design and should be treated accordingly.

21.5 PLANNING FOR UPRATING OR EXPANSION

All programs involving substation construction require planning. This is especially true of a program of

uprating or expansion.

The trend is toward assessment of existing substations and individual equipment to develop a predictive

maintenance and substation life extension program. This approach implements a planned program for

evaluating substation components and making modifications or individual equipment replacements to

improve reliability and extend the overall substation life.

Such a program can be operated in conjunction with uprating or expansion planning to optimize the

replacement and maintenance of substation equipment. For instance, major substation uprating or

expansion planning might include the replacement of existing electromechanical relays with

microprocessor relays for improved substation protection and monitoring.

Reliability analysis is being implemented in many maintenance programs to assess the probability of

failures and prioritize modifications based on safety, economics, obsolescence, and power quality.

Maintenance planning should be a part of the early stages of uprating or expansion projects. Such

planning includes visual inspections, periodic testing, maintaining of spare parts inventories, logging of

equipment test results, and logging of misoperations and maintenance records.
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Consider safety issues during the planning stages of any project. Provide and maintain proper tools,

personnel protective equipment, safety procedures, and safety training.

A Critical Path Method (CPM) or similar method is recommended for scheduling the actual uprating or

expansion activities. Include the detailed activities of engineering, material specification, procurement,

manufacturing, and delivery times together with itemized construction activities. The construction work

may need to be performed in phases to minimize outage time on particular circuits. Plan required service

outages to cause the least revenue loss and customer inconvenience. Factor into the program adequate

time to account for contingent delays that can and will occur. Inform customers of forthcoming service

outages so they can plan their activities around the outages.

Once the program or plan is developed, assign it to a qualified person to monitor the actual activities, both

office and field.

The program will probably require revision as time passes, but with a detailed plan, future problem areas

can be detected and appropriate action taken before they become crisis areas.

21.6 COMPARISONS—NEW VS. UPRATING OR EXPANSION

Successful substation uprating will require a high degree of technical cooperation between the

cooperative, the engineer, and the manufacturers’staff.

If uprating is just a stop-gap measure to favor a future program, ask the equipment manufacturer to

provide a reasonable life estimate of the uprated equipment. This will assist in the priority assignment of

the future program.

These comments apply largely to power transformers and, if history of operation shows a minimum of

operation above rated temperature, this life estimate can be quite reassuring.

New substation construction obviously causes the least disturbance, electrically, to the customers and the

system. In the case of a small installation, expansion can consist of duplicating the existing installation

and making a “hot” cutover or otherwise placing the new section in service with minimum outage. In this

case, if transformers are being paralleled, other chapters in this guide should be consulted for guidelines.

An expansion to existing facilities is on a par with uprating as to disturbance, but with good planning and

management of all phases of the program this can be kept to a minimum.

21.7 SUBSTATION UPGRADING

Substation upgrading by itself is difficult to justify because of the extent and cost of the modifications

normally required. However, when coupled with concurrent substation expansion, upgrading can often

become the best choice compared with construction of a completely new facility.

Substation modifications or upgrading are warranted when conditions affecting safety or security are

evident. Substations, particularly those of early vintage, may not meet current minimum recommended

requirements for insulation, electrical clearances, or structural integrity. In these instances, make a

thorough examination to determine the most efficient and economical method to improve the situation.

Construction of a new installation with ample provisions for future expansion may be the best choice,

particularly if extensive modifications are required.
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It should be noted that, because a standards group has lowered permissible operating temperatures or

made other standards changes to certain equipment or materials, if no trouble has been experienced and

maintenance is properly scheduled on existing equipment installed under the older standards, this

equipment need not be arbitrarily replaced.

21.8 REFERENCES

The Aluminum Association, Aluminum Electrical Conductor Handbook , New York: The Aluminum

Association, 1971.